System and method for an oxidant heating system

ABSTRACT

A system includes an oxidant compressor and a gas turbine engine. The gas turbine engine includes a combustor section having a turbine combustor, a turbine driven by combustion products from the turbine combustor, and an exhaust gas compressor driven by the turbine. The exhaust gas compressor is configured to compress and route an exhaust flow to the turbine combustor and the oxidant compressor is configured to compress and route an oxidant flow to the turbine combustor. The gas turbine engine also includes an inlet oxidant heating system configured to route at least one of a first portion of the combustion products, or a second portion of the exhaust flow, or any combination thereof, to an inlet of the oxidant compressor.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to and benefit of U.S. ProvisionalPatent Application No. 61/860,853, entitled “SYSTEM AND METHOD FOR ANOXIDANT HEATING SYSTEM,” filed on Jul. 31, 2013, which is herebyincorporated by reference in its entirety for all purposes.

BACKGROUND

The subject matter disclosed herein relates to gas turbine engines, andmore specifically, to systems and methods for an oxidant heating systemfor gas turbine engines.

Gas turbine engines are used in a wide variety of applications, such aspower generation, aircraft, and various machinery. Gas turbine enginesgenerally combust a fuel with an oxidant (e.g., air) in a combustorsection to generate hot combustion products, which then drive one ormore turbine stages of a turbine section. In turn, the turbine sectiondrives one or more compressor stages of a compressor section. Again, thefuel and oxidant mix in the combustor section, and then combust toproduce the hot combustion products. Under certain conditions, such aslow temperatures, the compressor section may be susceptible toundesirable issues, such as icing and/or surging. Therefore, it may bedesirable to increase an inlet temperature of the compressor section toreduce issues associated with low temperatures. Furthermore, gas turbineengines typically consume a vast amount of air as the oxidant, andoutput a considerable amount of exhaust gas into the atmosphere. Inother words, the exhaust gas is typically wasted as a byproduct of thegas turbine operation.

BRIEF DESCRIPTION

Certain embodiments commensurate in scope with the originally claimedinvention are summarized below. These embodiments are not intended tolimit the scope of the claimed invention, but rather these embodimentsare intended only to provide a brief summary of possible forms of theinvention. Indeed, the invention may encompass a variety of forms thatmay be similar to or different from the embodiments set forth below.

In a first embodiment, a system includes an oxidant compressor and a gasturbine engine. The gas turbine engine includes a combustor sectionhaving a turbine combustor, a turbine driven by combustion products fromthe turbine combustor, and an exhaust gas compressor driven by theturbine. The exhaust gas compressor is configured to compress and routean exhaust flow to the turbine combustor and the oxidant compressor isconfigured to compress and route an oxidant flow to the turbinecombustor. The gas turbine engine also includes an inlet oxidant heatingsystem configured to route at least one of a first portion of thecombustion products, or a second portion of the exhaust flow, or anycombination thereof, to an inlet of the oxidant compressor.

In a second embodiment, a method includes driving a turbine of a gasturbine engine with combustion products from a turbine combustor,driving an exhaust gas compressor using the turbine, compressing androuting an exhaust flow to the turbine combustor using the exhaust gascompressor, compressing and routing an oxidant flow to the turbinecombustor using an oxidant compressor, and routing at least one of afirst portion of the combustion products, or a second portion of theexhaust flow, or any combination thereof, to an inlet of the oxidantcompressor.

In a third embodiment, a system includes instructions disposed on anon-transitory, machine readable medium. The instructions are configuredto drive a turbine of a gas turbine engine with combustion products froma turbine combustor, drive an exhaust gas compressor using the turbine,compress and route an exhaust flow to the turbine combustor using theexhaust gas compressor, compress and route an oxidant flow to theturbine combustor using an oxidant compressor, and route at least one ofa first portion of the combustion products, or a second portion of theexhaust flow, or any combination thereof, to an inlet of the oxidantcompressor.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of the presentinvention will become better understood when the following detaileddescription is read with reference to the accompanying drawings in whichlike characters represent like parts throughout the drawings, wherein:

FIG. 1 is a diagram of an embodiment of a system having a turbine-basedservice system coupled to a hydrocarbon production system;

FIG. 2 is a diagram of an embodiment of the system of FIG. 1, furtherillustrating a control system and a combined cycle system;

FIG. 3 is a diagram of an embodiment of the system of FIGS. 1 and 2,further illustrating details of a gas turbine engine, exhaust gas supplysystem, and exhaust gas processing system;

FIG. 4 is a flow chart of an embodiment of a process for operating thesystem of FIGS. 1-3;

FIG. 5 is a schematic diagram of an embodiment of an oxidant compressorof a gas turbine system with an inlet oxidant heating system;

FIG. 6 is a schematic diagram of an embodiment of a gas turbine enginesystem with an inlet oxidant heating system; and

FIG. 7 is a schematic diagram of an embodiment of a gas turbine enginesystem with an inlet oxidant heating system with a plurality of heatingsources.

DETAILED DESCRIPTION

One or more specific embodiments of the present invention will bedescribed below. In an effort to provide a concise description of theseembodiments, all features of an actual implementation may not bedescribed in the specification. It should be appreciated that in thedevelopment of any such actual implementation, as in an engineering ordesign project, numerous implementation-specific decisions are made toachieve the specific goals, such as compliance with system-relatedand/or business-related constraints, which may vary from oneimplementation to another. Moreover, it should be appreciated that sucheffort might be complex and time consuming, but would nevertheless be aroutine undertaking of design, fabrication, and manufacture for those ofordinary skill having the benefit of this disclosure.

Detailed example embodiments are disclosed herein. However, specificstructural and functional details disclosed herein are merelyrepresentative for purposes of describing example embodiments.Embodiments of the present invention may, however, be embodied in manyalternate forms, and should not be construed as limited to only theembodiments set forth herein.

Accordingly, while example embodiments are capable of variousmodifications and alternative forms, embodiments thereof are illustratedby way of example in the figures and will herein be described in detail.It should be understood, however, that there is no intent to limitexample embodiments to the particular forms disclosed, but to thecontrary, example embodiments are to cover all modifications,equivalents, and alternatives falling within the scope of the presentinvention.

The terminology used herein is for describing particular embodimentsonly and is not intended to be limiting of example embodiments. As usedherein, the singular forms “a”, “an” and “the” are intended to includethe plural forms as well, unless the context clearly indicatesotherwise. The terms “comprises”, “comprising”, “includes” and/or“including”, when used herein, specify the presence of stated features,integers, steps, operations, elements, and/or components, but do notpreclude the presence or addition of one or more other features,integers, steps, operations, elements, components, and/or groupsthereof.

Although the terms first, second, primary, secondary, etc. may be usedherein to describe various elements, these elements should not belimited by these terms. These terms are only used to distinguish oneelement from another. For example, but not limiting to, a first elementcould be termed a second element, and, similarly, a second element couldbe termed a first element, without departing from the scope of exampleembodiments. As used herein, the term “and/or” includes any, and all,combinations of one or more of the associated listed items.

Certain terminology may be used herein for the convenience of the readeronly and is not to be taken as a limitation on the scope of theinvention. For example, words such as “upper”, “lower”, “left”, “right”,“front”, “rear”, “top”, “bottom”, “horizontal”, “vertical”, “upstream”,“downstream”, “fore”, “aft”, and the like; merely describe theconfiguration shown in the FIGS. Indeed, the element or elements of anembodiment of the present invention may be oriented in any direction andthe terminology, therefore, should be understood as encompassing suchvariations unless specified otherwise.

As discussed in detail below, the disclosed embodiments relate generallyto gas turbine systems with exhaust gas recirculation (EGR), andparticularly stoichiometric operation of the gas turbine systems usingEGR. For example, the gas turbine systems may be configured torecirculate the exhaust gas along an exhaust recirculation path,stoichiometrically combust fuel and oxidant along with at least some ofthe recirculated exhaust gas, and capture the exhaust gas for use invarious target systems. The recirculation of the exhaust gas along withstoichiometric combustion may help to increase the concentration levelof carbon dioxide (CO₂) in the exhaust gas, which can then be posttreated to separate and purify the CO₂ and nitrogen (N₂) for use invarious target systems. The gas turbine systems also may employ variousexhaust gas processing (e.g., heat recovery, catalyst reactions, etc.)along the exhaust recirculation path, thereby increasing theconcentration level of CO₂, reducing concentration levels of otheremissions (e.g., carbon monoxide, nitrogen oxides, and unburnthydrocarbons), and increasing energy recovery (e.g., with heat recoveryunits). Furthermore, the gas turbine engines may be configured tocombust the fuel and oxidant with one or more diffusion flames (e.g.,using diffusion fuel nozzles), premix flames (e.g., using premix fuelnozzles), or any combination thereof. In certain embodiments, thediffusion flames may help to maintain stability and operation withincertain limits for stoichiometric combustion, which in turn helps toincrease production of CO₂. For example, a gas turbine system operatingwith diffusion flames may enable a greater quantity of EGR, as comparedto a gas turbine system operating with premix flames. In turn, theincreased quantity of EGR helps to increase CO₂ production. Possibletarget systems include pipelines, storage tanks, carbon sequestrationsystems, and hydrocarbon production systems, such as enhanced oilrecovery (EOR) systems.

The disclosed embodiments provide systems and methods for an inletoxidant heating system used with a gas turbine engine with EGR.Specifically, the gas turbine engine may include a combustor sectionhaving a turbine combustor, a turbine driven by combustion products fromthe turbine combustor, and an exhaust gas compressor driven by theturbine. The exhaust gas compressor may compress and route an exhaustflow to the turbine combustor and an oxidant compressor may compress androute an oxidant flow to the turbine combustor. The inlet oxidantheating system may route at least one of a first portion of thecombustion products, or a second portion of the exhaust flow, or anycombustion thereof, to an inlet of the oxidant compressor. For example,the inlet of the oxidant compressor may convey ambient air to theoxidant compressor to be compressed and routed to the turbine combustor.A temperature of the first portion of the combustion products, or thesecond portion of the exhaust flow, or any combination thereof, may begreater than a temperature of the ambient air. Thus, by combining thefirst portion of the combustion products, or the second portion of theexhaust flow, or any combustion thereof, with the ambient air, the inletoxidant heating system may increase a temperature of the mixtureentering the oxidant compressor. In some embodiments, the first portionof the combustion products, or a second portion of the exhaust flow, orany combustion thereof, may come from the gas turbine engine with EGR orone or more other gas turbine engines, such as gas turbine engineslocated in parallel trains, which may or may not have EGR.

By increasing the temperate of the mixture entering the oxidantcompressor, the inlet oxidant heating system may help prevent certainundesirable issues associated with low ambient temperatures, such asicing and/or surging. Specifically, icing may occur when low ambient airtemperatures cause water vapor in the ambient air to freeze upon contactwith components of the oxidant compressor. The ice may build up untilthe ice breaks off and enters the moving components of the oxidantcompressor, possibly affecting operation of the oxidant compressor.Surging may occur when the oxidant compressor is unable to compress theoxidant to a desired pressure, thereby causing a flow reversal, whichmay affect operation of the oxidant compressor. By heating the mixtureentering the oxidant compressor, the oxidant heating system may helpprevent icing by avoiding conditions at which water may freeze on thecomponents of the oxidant compressor. In addition, the use of the inletoxidant heating system may enable inlet guide vanes of the oxidantcompressor to operate in a more open position, thereby helping toprevent conditions at which surging may occur. Although other methodsmay be used to heat the oxidant entering the oxidant compressor, use ofthe first portion of the combustion products, or the second portion ofthe exhaust flow, or any combination thereof, may be desirable becausethese gases are readily available at temperatures and pressures thatmake them useful for heating the oxidant. In addition, these gases maybe compatible with the oxidant being compressed in the oxidantcompressor and routed to the turbine combustor of the gas turbineengine. Thus, use of the inlet oxidant heating system may increase theoverall efficiency of the SEGR gas turbine system and/or reduceoperating costs of the SEGR gas turbine system.

FIG. 1 is a diagram of an embodiment of a system 10 having anhydrocarbon production system 12 associated with a turbine-based servicesystem 14. As discussed in further detail below, various embodiments ofthe turbine-based service system 14 are configured to provide variousservices, such as electrical power, mechanical power, and fluids (e.g.,exhaust gas), to the hydrocarbon production system 12 to facilitate theproduction or retrieval of oil and/or gas. In the illustratedembodiment, the hydrocarbon production system 12 includes an oil/gasextraction system 16 and an enhanced oil recovery (EOR) system 18, whichare coupled to a subterranean reservoir 20 (e.g., an oil, gas, orhydrocarbon reservoir). The oil/gas extraction system 16 includes avariety of surface equipment 22, such as a Christmas tree or productiontree 24, coupled to an oil/gas well 26. Furthermore, the well 26 mayinclude one or more tubulars 28 extending through a drilled bore 30 inthe earth 32 to the subterranean reservoir 20. The tree 24 includes oneor more valves, chokes, isolation sleeves, blowout preventers, andvarious flow control devices, which regulate pressures and control flowsto and from the subterranean reservoir 20. While the tree 24 isgenerally used to control the flow of the production fluid (e.g., oil orgas) out of the subterranean reservoir 20, the EOR system 18 mayincrease the production of oil or gas by injecting one or more fluidsinto the subterranean reservoir 20.

Accordingly, the EOR system 18 may include a fluid injection system 34,which has one or more tubulars 36 extending through a bore 38 in theearth 32 to the subterranean reservoir 20. For example, the EOR system18 may route one or more fluids 40, such as gas, steam, water,chemicals, or any combination thereof, into the fluid injection system34. For example, as discussed in further detail below, the EOR system 18may be coupled to the turbine-based service system 14, such that thesystem 14 routes an exhaust gas 42 (e.g., substantially or entirely freeof oxygen) to the EOR system 18 for use as the injection fluid 40. Thefluid injection system 34 routes the fluid 40 (e.g., the exhaust gas 42)through the one or more tubulars 36 into the subterranean reservoir 20,as indicated by arrows 44. The injection fluid 40 enters thesubterranean reservoir 20 through the tubular 36 at an offset distance46 away from the tubular 28 of the oil/gas well 26. Accordingly, theinjection fluid 40 displaces the oil/gas 48 disposed in the subterraneanreservoir 20, and drives the oil/gas 48 up through the one or moretubulars 28 of the hydrocarbon production system 12, as indicated byarrows 50. As discussed in further detail below, the injection fluid 40may include the exhaust gas 42 originating from the turbine-basedservice system 14, which is able to generate the exhaust gas 42 on-siteas needed by the hydrocarbon production system 12. In other words, theturbine-based system 14 may simultaneously generate one or more services(e.g., electrical power, mechanical power, steam, water (e.g.,desalinated water), and exhaust gas (e.g., substantially free ofoxygen)) for use by the hydrocarbon production system 12, therebyreducing or eliminating the reliance on external sources of suchservices.

In the illustrated embodiment, the turbine-based service system 14includes a stoichiometric exhaust gas recirculation (SEGR) gas turbinesystem 52 and an exhaust gas (EG) processing system 54. The gas turbinesystem 52 may be configured to operate in a stoichiometric combustionmode of operation (e.g., a stoichiometric control mode) and anon-stoichiometric combustion mode of operation (e.g., anon-stoichiometric control mode), such as a fuel-lean control mode or afuel-rich control mode. In the stoichiometric control mode, thecombustion generally occurs in a substantially stoichiometric ratio of afuel and oxidant, thereby resulting in substantially stoichiometriccombustion. In particular, stoichiometric combustion generally involvesconsuming substantially all of the fuel and oxidant in the combustionreaction, such that the products of combustion are substantially orentirely free of unburnt fuel and oxidant. One measure of stoichiometriccombustion is the equivalence ratio, or phi (Φ), which is the ratio ofthe actual fuel/oxidant ratio relative to the stoichiometricfuel/oxidant ratio. An equivalence ratio of greater than 1.0 results ina fuel-rich combustion of the fuel and oxidant, whereas an equivalenceratio of less than 1.0 results in a fuel-lean combustion of the fuel andoxidant. In contrast, an equivalence ratio of 1.0 results in combustionthat is neither fuel-rich nor fuel-lean, thereby substantially consumingall of the fuel and oxidant in the combustion reaction. In context ofthe disclosed embodiments, the term stoichiometric or substantiallystoichiometric may refer to an equivalence ratio of approximately 0.95to approximately 1.05. However, the disclosed embodiments may alsoinclude an equivalence ratio of 1.0 plus or minus 0.01, 0.02, 0.03,0.04, 0.05, or more. Again, the stoichiometric combustion of fuel andoxidant in the turbine-based service system 14 may result in products ofcombustion or exhaust gas (e.g., 42) with substantially no unburnt fuelor oxidant remaining. For example, the exhaust gas 42 may have less than1, 2, 3, 4, or 5 percent by volume of oxidant (e.g., oxygen), unburntfuel or hydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO_(X)), carbonmonoxide (CO), sulfur oxides (e.g., SO_(X)), hydrogen, and otherproducts of incomplete combustion. By further example, the exhaust gas42 may have less than approximately 10, 20, 30, 40, 50, 60, 70, 80, 90,100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, or 5000 parts permillion by volume (ppmv) of oxidant (e.g., oxygen), unburnt fuel orhydrocarbons (e.g., HCs), nitrogen oxides (e.g., NO_(X)), carbonmonoxide (CO), sulfur oxides (e.g., SO_(X)), hydrogen, and otherproducts of incomplete combustion. However, the disclosed embodimentsalso may produce other ranges of residual fuel, oxidant, and otheremissions levels in the exhaust gas 42. As used herein, the termsemissions, emissions levels, and emissions targets may refer toconcentration levels of certain products of combustion (e.g., NO_(X),CO, SO_(X), O₂, N₂, H₂, HCs, etc.), which may be present in recirculatedgas streams, vented gas streams (e.g., exhausted into the atmosphere),and gas streams used in various target systems (e.g., the hydrocarbonproduction system 12).

Although the SEGR gas turbine system 52 and the EG processing system 54may include a variety of components in different embodiments, theillustrated EG processing system 54 includes a heat recovery steamgenerator (HRSG) 56 and an exhaust gas recirculation (EGR) system 58,which receive and process an exhaust gas 60 originating from the SEGRgas turbine system 52. The HRSG 56 may include one or more heatexchangers, condensers, and various heat recovery equipment, whichcollectively function to transfer heat from the exhaust gas 60 to astream of water, thereby generating steam 62. The steam 62 may be usedin one or more steam turbines, the EOR system 18, or any other portionof the hydrocarbon production system 12. For example, the HRSG 56 maygenerate low pressure, medium pressure, and/or high pressure steam 62,which may be selectively applied to low, medium, and high pressure steamturbine stages, or different applications of the EOR system 18. Inaddition to the steam 62, a treated water 64, such as a desalinatedwater, may be generated by the HRSG 56, the EGR system 58, and/oranother portion of the EG processing system 54 or the SEGR gas turbinesystem 52. The treated water 64 (e.g., desalinated water) may beparticularly useful in areas with water shortages, such as inland ordesert regions. The treated water 64 may be generated, at least in part,due to the large volume of air driving combustion of fuel within theSEGR gas turbine system 52. While the on-site generation of steam 62 andwater 64 may be beneficial in many applications (including thehydrocarbon production system 12), the on-site generation of exhaust gas42, 60 may be particularly beneficial for the EOR system 18, due to itslow oxygen content, high pressure, and heat derived from the SEGR gasturbine system 52. Accordingly, the HRSG 56, the EGR system 58, and/oranother portion of the EG processing system 54 may output or recirculatean exhaust gas 66 into the SEGR gas turbine system 52, while alsorouting the exhaust gas 42 to the EOR system 18 for use with thehydrocarbon production system 12. Likewise, the exhaust gas 42 may beextracted directly from the SEGR gas turbine system 52 (i.e., withoutpassing through the EG processing system 54) for use in the EOR system18 of the hydrocarbon production system 12.

The exhaust gas recirculation is handled by the EGR system 58 of the EGprocessing system 54. For example, the EGR system 58 includes one ormore conduits, valves, blowers, exhaust gas treatment systems (e.g.,filters, particulate removal units, gas separation units, gaspurification units, heat exchangers, heat recovery units, moistureremoval units, catalyst units, chemical injection units, or anycombination thereof), and controls to recirculate the exhaust gas alongan exhaust gas circulation path from an output (e.g., discharged exhaustgas 60) to an input (e.g., intake exhaust gas 66) of the SEGR gasturbine system 52. In the illustrated embodiment, the SEGR gas turbinesystem 52 intakes the exhaust gas 66 into a compressor section havingone or more compressors, thereby compressing the exhaust gas 66 for usein a combustor section along with an intake of an oxidant 68 and one ormore fuels 70. The oxidant 68 may include ambient air, pure oxygen,oxygen-enriched air, oxygen-reduced air, oxygen-nitrogen mixtures, orany suitable oxidant that facilitates combustion of the fuel 70. Thefuel 70 may include one or more gas fuels, liquid fuels, or anycombination thereof. For example, the fuel 70 may include natural gas,liquefied natural gas (LNG), syngas, methane, ethane, propane, butane,naphtha, kerosene, diesel fuel, ethanol, methanol, biofuel, or anycombination thereof.

The SEGR gas turbine system 52 mixes and combusts the exhaust gas 66,the oxidant 68, and the fuel 70 in the combustor section, therebygenerating hot combustion gases or exhaust gas 60 to drive one or moreturbine stages in a turbine section. In certain embodiments, eachcombustor in the combustor section includes one or more premix fuelnozzles, one or more diffusion fuel nozzles, or any combination thereof.For example, each premix fuel nozzle may be configured to mix theoxidant 68 and the fuel 70 internally within the fuel nozzle and/orpartially upstream of the fuel nozzle, thereby injecting an oxidant-fuelmixture from the fuel nozzle into the combustion zone for a premixedcombustion (e.g., a premixed flame). By further example, each diffusionfuel nozzle may be configured to isolate the flows of oxidant 68 andfuel 70 within the fuel nozzle, thereby separately injecting the oxidant68 and the fuel 70 from the fuel nozzle into the combustion zone fordiffusion combustion (e.g., a diffusion flame). In particular, thediffusion combustion provided by the diffusion fuel nozzles delaysmixing of the oxidant 68 and the fuel 70 until the point of initialcombustion, i.e., the flame region. In embodiments employing thediffusion fuel nozzles, the diffusion flame may provide increased flamestability, because the diffusion flame generally forms at the point ofstoichiometry between the separate streams of oxidant 68 and fuel 70(i.e., as the oxidant 68 and fuel 70 are mixing). In certainembodiments, one or more diluents (e.g., the exhaust gas 60, steam,nitrogen, or another inert gas) may be pre-mixed with the oxidant 68,the fuel 70, or both, in either the diffusion fuel nozzle or the premixfuel nozzle. In addition, one or more diluents (e.g., the exhaust gas60, steam, nitrogen, or another inert gas) may be injected into thecombustor at or downstream from the point of combustion within eachcombustor. The use of these diluents may help temper the flame (e.g.,premix flame or diffusion flame), thereby helping to reduce NO_(X)emissions, such as nitrogen monoxide (NO) and nitrogen dioxide (NO₂).Regardless of the type of flame, the combustion produces hot combustiongases or exhaust gas 60 to drive one or more turbine stages. As eachturbine stage is driven by the exhaust gas 60, the SEGR gas turbinesystem 52 generates a mechanical power 72 and/or an electrical power 74(e.g., via an electrical generator). The system 52 also outputs theexhaust gas 60, and may further output water 64. Again, the water 64 maybe a treated water, such as a desalinated water, which may be useful ina variety of applications on-site or off-site.

Exhaust extraction is also provided by the SEGR gas turbine system 52using one or more extraction points 76. For example, the illustratedembodiment includes an exhaust gas (EG) supply system 78 having anexhaust gas (EG) extraction system 80 and an exhaust gas (EG) treatmentsystem 82, which receive exhaust gas 42 from the extraction points 76,treat the exhaust gas 42, and then supply or distribute the exhaust gas42 to various target systems. The target systems may include the EORsystem 18 and/or other systems, such as a pipeline 86, a storage tank88, or a carbon sequestration system 90. The EG extraction system 80 mayinclude one or more conduits, valves, controls, and flow separations,which facilitate isolation of the exhaust gas 42 from the oxidant 68,the fuel 70, and other contaminants, while also controlling thetemperature, pressure, and flow rate of the extracted exhaust gas 42.The EG treatment system 82 may include one or more heat exchangers(e.g., heat recovery units such as heat recovery steam generators,condensers, coolers, or heaters), catalyst systems (e.g., oxidationcatalyst systems), particulate and/or water removal systems (e.g., gasdehydration units, inertial separators, coalescing filters, waterimpermeable filters, and other filters), chemical injection systems,solvent based treatment systems (e.g., absorbers, flash tanks, etc.),carbon capture systems, gas separation systems, gas purificationsystems, and/or a solvent based treatment system, exhaust gascompressors, any combination thereof. These subsystems of the EGtreatment system 82 enable control of the temperature, pressure, flowrate, moisture content (e.g., amount of water removal), particulatecontent (e.g., amount of particulate removal), and gas composition(e.g., percentage of CO₂, N₂, etc.).

The extracted exhaust gas 42 is treated by one or more subsystems of theEG treatment system 82, depending on the target system. For example, theEG treatment system 82 may direct all or part of the exhaust gas 42through a carbon capture system, a gas separation system, a gaspurification system, and/or a solvent based treatment system, which iscontrolled to separate and purify a carbonaceous gas (e.g., carbondioxide) 92 and/or nitrogen (N₂) 94 for use in the various targetsystems. For example, embodiments of the EG treatment system 82 mayperform gas separation and purification to produce a plurality ofdifferent streams 95 of exhaust gas 42, such as a first stream 96, asecond stream 97, and a third stream 98. The first stream 96 may have afirst composition that is rich in carbon dioxide and/or lean in nitrogen(e.g., a CO₂ rich, N₂ lean stream). The second stream 97 may have asecond composition that has intermediate concentration levels of carbondioxide and/or nitrogen (e.g., intermediate concentration CO₂, N₂stream). The third stream 98 may have a third composition that is leanin carbon dioxide and/or rich in nitrogen (e.g., a CO₂ lean, N₂ richstream). Each stream 95 (e.g., 96, 97, and 98) may include a gasdehydration unit, a filter, a gas compressor, or any combinationthereof, to facilitate delivery of the stream 95 to a target system. Incertain embodiments, the CO₂ rich, N₂ lean stream 96 may have a CO₂purity or concentration level of greater than approximately 70, 75, 80,85, 90, 95, 96, 97, 98, or 99 percent by volume, and a N₂ purity orconcentration level of less than approximately 1, 2, 3, 4, 5, 10, 15,20, 25, or 30 percent by volume. In contrast, the CO₂ lean, N₂ richstream 98 may have a CO₂ purity or concentration level of less thanapproximately 1, 2, 3, 4, 5, 10, 15, 20, 25, or 30 percent by volume,and a N₂ purity or concentration level of greater than approximately 70,75, 80, 85, 90, 95, 96, 97, 98, or 99 percent by volume. Theintermediate concentration CO₂, N₂ stream 97 may have a CO₂ purity orconcentration level and/or a N₂ purity or concentration level of betweenapproximately 30 to 70, 35 to 65, 40 to 60, or 45 to 55 percent byvolume. Although the foregoing ranges are merely non-limiting examples,the CO₂ rich, N₂ lean stream 96 and the CO₂ lean, N₂ rich stream 98 maybe particularly well suited for use with the EOR system 18 and the othersystems 84. However, any of these rich, lean, or intermediateconcentration CO₂ streams 95 may be used, alone or in variouscombinations, with the EOR system 18 and the other systems 84. Forexample, the EOR system 18 and the other systems 84 (e.g., the pipeline86, storage tank 88, and the carbon sequestration system 90) each mayreceive one or more CO₂ rich, N₂ lean streams 96, one or more CO₂ lean,N₂ rich streams 98, one or more intermediate concentration CO₂, N₂streams 97, and one or more untreated exhaust gas 42 streams (i.e.,bypassing the EG treatment system 82).

The EG extraction system 80 extracts the exhaust gas 42 at one or moreextraction points 76 along the compressor section, the combustorsection, and/or the turbine section, such that the exhaust gas 42 may beused in the EOR system 18 and other systems 84 at suitable temperaturesand pressures. The EG extraction system 80 and/or the EG treatmentsystem 82 also may circulate fluid flows (e.g., exhaust gas 42) to andfrom the EG processing system 54. For example, a portion of the exhaustgas 42 passing through the EG processing system 54 may be extracted bythe EG extraction system 80 for use in the EOR system 18 and the othersystems 84. In certain embodiments, the EG supply system 78 and the EGprocessing system 54 may be independent or integral with one another,and thus may use independent or common subsystems. For example, the EGtreatment system 82 may be used by both the EG supply system 78 and theEG processing system 54. Exhaust gas 42 extracted from the EG processingsystem 54 may undergo multiple stages of gas treatment, such as one ormore stages of gas treatment in the EG processing system 54 followed byone or more additional stages of gas treatment in the EG treatmentsystem 82.

At each extraction point 76, the extracted exhaust gas 42 may besubstantially free of oxidant 68 and fuel 70 (e.g., unburnt fuel orhydrocarbons) due to substantially stoichiometric combustion and/or gastreatment in the EG processing system 54. Furthermore, depending on thetarget system, the extracted exhaust gas 42 may undergo furthertreatment in the EG treatment system 82 of the EG supply system 78,thereby further reducing any residual oxidant 68, fuel 70, or otherundesirable products of combustion. For example, either before or aftertreatment in the EG treatment system 82, the extracted exhaust gas 42may have less than 1, 2, 3, 4, or 5 percent by volume of oxidant (e.g.,oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides(e.g., NO_(X)), carbon monoxide (CO), sulfur oxides (e.g., SO_(X)),hydrogen, and other products of incomplete combustion. By furtherexample, either before or after treatment in the EG treatment system 82,the extracted exhaust gas 42 may have less than approximately 10, 20,30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000,4000, or 5000 parts per million by volume (ppmv) of oxidant (e.g.,oxygen), unburnt fuel or hydrocarbons (e.g., HCs), nitrogen oxides(e.g., NO_(X)), carbon monoxide (CO), sulfur oxides (e.g., SO_(X)),hydrogen, and other products of incomplete combustion. Thus, the exhaustgas 42 is particularly well suited for use with the EOR system 18.

The EGR operation of the turbine system 52 specifically enables theexhaust extraction at a multitude of locations 76. For example, thecompressor section of the system 52 may be used to compress the exhaustgas 66 without any oxidant 68 (i.e., only compression of the exhaust gas66), such that a substantially oxygen-free exhaust gas 42 may beextracted from the compressor section and/or the combustor section priorto entry of the oxidant 68 and the fuel 70. The extraction points 76 maybe located at interstage ports between adjacent compressor stages, atports along the compressor discharge casing, at ports along eachcombustor in the combustor section, or any combination thereof. Incertain embodiments, the exhaust gas 66 may not mix with the oxidant 68and fuel 70 until it reaches the head end portion and/or fuel nozzles ofeach combustor in the combustor section. Furthermore, one or more flowseparators (e.g., walls, dividers, baffles, or the like) may be used toisolate the oxidant 68 and the fuel 70 from the extraction points 76.With these flow separators, the extraction points 76 may be disposeddirectly along a wall of each combustor in the combustor section.

Once the exhaust gas 66, oxidant 68, and fuel 70 flow through the headend portion (e.g., through fuel nozzles) into the combustion portion(e.g., combustion chamber) of each combustor, the SEGR gas turbinesystem 52 is controlled to provide a substantially stoichiometriccombustion of the exhaust gas 66, oxidant 68, and fuel 70. For example,the system 52 may maintain an equivalence ratio of approximately 0.95 toapproximately 1.05. As a result, the products of combustion of themixture of exhaust gas 66, oxidant 68, and fuel 70 in each combustor issubstantially free of oxygen and unburnt fuel. Thus, the products ofcombustion (or exhaust gas) may be extracted from the turbine section ofthe SEGR gas turbine system 52 for use as the exhaust gas 42 routed tothe EOR system 18. Along the turbine section, the extraction points 76may be located at any turbine stage, such as interstage ports betweenadjacent turbine stages. Thus, using any of the foregoing extractionpoints 76, the turbine-based service system 14 may generate, extract,and deliver the exhaust gas 42 to the hydrocarbon production system 12(e.g., the EOR system 18) for use in the production of oil/gas 48 fromthe subterranean reservoir 20.

FIG. 2 is a diagram of an embodiment of the system 10 of FIG. 1,illustrating a control system 100 coupled to the turbine-based servicesystem 14 and the hydrocarbon production system 12. In the illustratedembodiment, the turbine-based service system 14 includes a combinedcycle system 102, which includes the SEGR gas turbine system 52 as atopping cycle, a steam turbine 104 as a bottoming cycle, and the HRSG 56to recover heat from the exhaust gas 60 to generate the steam 62 fordriving the steam turbine 104. Again, the SEGR gas turbine system 52receives, mixes, and stoichiometrically combusts the exhaust gas 66, theoxidant 68, and the fuel 70 (e.g., premix and/or diffusion flames),thereby producing the exhaust gas 60, the mechanical power 72, theelectrical power 74, and/or the water 64. For example, the SEGR gasturbine system 52 may drive one or more loads or machinery 106, such asan electrical generator, an oxidant compressor (e.g., a main aircompressor), a gear box, a pump, equipment of the hydrocarbon productionsystem 12, or any combination thereof. In some embodiments, themachinery 106 may include other drives, such as electrical motors orsteam turbines (e.g., the steam turbine 104), in tandem with the SEGRgas turbine system 52. Accordingly, an output of the machinery 106driven by the SEGR gas turbines system 52 (and any additional drives)may include the mechanical power 72 and the electrical power 74. Themechanical power 72 and/or the electrical power 74 may be used on-sitefor powering the hydrocarbon production system 12, the electrical power74 may be distributed to the power grid, or any combination thereof. Theoutput of the machinery 106 also may include a compressed fluid, such asa compressed oxidant 68 (e.g., air or oxygen), for intake into thecombustion section of the SEGR gas turbine system 52. Each of theseoutputs (e.g., the exhaust gas 60, the mechanical power 72, theelectrical power 74, and/or the water 64) may be considered a service ofthe turbine-based service system 14.

The SEGR gas turbine system 52 produces the exhaust gas 42, 60, whichmay be substantially free of oxygen, and routes this exhaust gas 42, 60to the EG processing system 54 and/or the EG supply system 78. The EGsupply system 78 may treat and delivery the exhaust gas 42 (e.g.,streams 95) to the hydrocarbon production system 12 and/or the othersystems 84. As discussed above, the EG processing system 54 may includethe HRSG 56 and the EGR system 58. The HRSG 56 may include one or moreheat exchangers, condensers, and various heat recovery equipment, whichmay be used to recover or transfer heat from the exhaust gas 60 to water108 to generate the steam 62 for driving the steam turbine 104. Similarto the SEGR gas turbine system 52, the steam turbine 104 may drive oneor more loads or machinery 106, thereby generating the mechanical power72 and the electrical power 74. In the illustrated embodiment, the SEGRgas turbine system 52 and the steam turbine 104 are arranged in tandemto drive the same machinery 106. However, in other embodiments, the SEGRgas turbine system 52 and the steam turbine 104 may separately drivedifferent machinery 106 to independently generate mechanical power 72and/or electrical power 74. As the steam turbine 104 is driven by thesteam 62 from the HRSG 56, the steam 62 gradually decreases intemperature and pressure. Accordingly, the steam turbine 104recirculates the used steam 62 and/or water 108 back into the HRSG 56for additional steam generation via heat recovery from the exhaust gas60. In addition to steam generation, the HRSG 56, the EGR system 58,and/or another portion of the EG processing system 54 may produce thewater 64, the exhaust gas 42 for use with the hydrocarbon productionsystem 12, and the exhaust gas 66 for use as an input into the SEGR gasturbine system 52. For example, the water 64 may be a treated water 64,such as a desalinated water for use in other applications. Thedesalinated water may be particularly useful in regions of low wateravailability. Regarding the exhaust gas 60, embodiments of the EGprocessing system 54 may be configured to recirculate the exhaust gas 60through the EGR system 58 with or without passing the exhaust gas 60through the HRSG 56.

In the illustrated embodiment, the SEGR gas turbine system 52 has anexhaust recirculation path 110, which extends from an exhaust outlet toan exhaust inlet of the system 52. Along the path 110, the exhaust gas60 passes through the EG processing system 54, which includes the HRSG56 and the EGR system 58 in the illustrated embodiment. The EGR system58 may include one or more conduits, valves, blowers, gas treatmentsystems (e.g., filters, particulate removal units, gas separation units,gas purification units, heat exchangers, heat recovery units such asheat recovery steam generators, moisture removal units, catalyst units,chemical injection units, or any combination thereof) in series and/orparallel arrangements along the path 110. In other words, the EGR system58 may include any flow control components, pressure control components,temperature control components, moisture control components, and gascomposition control components along the exhaust recirculation path 110between the exhaust outlet and the exhaust inlet of the system 52.Accordingly, in embodiments with the HRSG 56 along the path 110, theHRSG 56 may be considered a component of the EGR system 58. However, incertain embodiments, the HRSG 56 may be disposed along an exhaust pathindependent from the exhaust recirculation path 110. Regardless ofwhether the HRSG 56 is along a separate path or a common path with theEGR system 58, the HRSG 56 and the EGR system 58 intake the exhaust gas60 and output either the recirculated exhaust gas 66, the exhaust gas 42for use with the EG supply system 78 (e.g., for the hydrocarbonproduction system 12 and/or other systems 84), or another output ofexhaust gas. Again, the SEGR gas turbine system 52 intakes, mixes, andstoichiometrically combusts the exhaust gas 66, the oxidant 68, and thefuel 70 (e.g., premixed and/or diffusion flames) to produce asubstantially oxygen-free and fuel-free exhaust gas 60 for distributionto the EG processing system 54, the hydrocarbon production system 12, orother systems 84.

As noted above with reference to FIG. 1, the hydrocarbon productionsystem 12 may include a variety of equipment to facilitate the recoveryor production of oil/gas 48 from a subterranean reservoir 20 through anoil/gas well 26. For example, the hydrocarbon production system 12 mayinclude the EOR system 18 having the fluid injection system 34. In theillustrated embodiment, the fluid injection system 34 includes anexhaust gas injection EOR system 112 and a steam injection EOR system114. Although the fluid injection system 34 may receive fluids from avariety of sources, the illustrated embodiment may receive the exhaustgas 42 and the steam 62 from the turbine-based service system 14. Theexhaust gas 42 and/or the steam 62 produced by the turbine-based servicesystem 14 also may be routed to the hydrocarbon production system 12 foruse in other oil/gas systems 116.

The quantity, quality, and flow of the exhaust gas 42 and/or the steam62 may be controlled by the control system 100. The control system 100may be dedicated entirely to the turbine-based service system 14, or thecontrol system 100 may optionally also provide control (or at least somedata to facilitate control) for the hydrocarbon production system 12and/or other systems 84. In the illustrated embodiment, the controlsystem 100 includes a controller 118 having a processor 120, a memory122, a steam turbine control 124, a SEGR gas turbine system control 126,and a machinery control 128. The processor 120 may include a singleprocessor or two or more redundant processors, such as triple redundantprocessors for control of the turbine-based service system 14. Thememory 122 may include volatile and/or non-volatile memory. For example,the memory 122 may include one or more hard drives, flash memory,read-only memory, random access memory, or any combination thereof. Thecontrols 124, 126, and 128 may include software and/or hardwarecontrols. For example, the controls 124, 126, and 128 may includevarious instructions or code stored on the memory 122 and executable bythe processor 120. The control 124 is configured to control operation ofthe steam turbine 104, the SEGR gas turbine system control 126 isconfigured to control the system 52, and the machinery control 128 isconfigured to control the machinery 106. Thus, the controller 118 (e.g.,controls 124, 126, and 128) may be configured to coordinate varioussub-systems of the turbine-based service system 14 to provide a suitablestream of the exhaust gas 42 to the hydrocarbon production system 12.

In certain embodiments of the control system 100, each element (e.g.,system, subsystem, and component) illustrated in the drawings ordescribed herein includes (e.g., directly within, upstream, ordownstream of such element) one or more industrial control features,such as sensors and control devices, which are communicatively coupledwith one another over an industrial control network along with thecontroller 118. For example, the control devices associated with eachelement may include a dedicated device controller (e.g., including aprocessor, memory, and control instructions), one or more actuators,valves, switches, and industrial control equipment, which enable controlbased on sensor feedback 130, control signals from the controller 118,control signals from a user, or any combination thereof. Thus, any ofthe control functionality described herein may be implemented withcontrol instructions stored and/or executable by the controller 118,dedicated device controllers associated with each element, or acombination thereof.

In order to facilitate such control functionality, the control system100 includes one or more sensors distributed throughout the system 10 toobtain the sensor feedback 130 for use in execution of the variouscontrols, e.g., the controls 124, 126, and 128. For example, the sensorfeedback 130 may be obtained from sensors distributed throughout theSEGR gas turbine system 52, the machinery 106, the EG processing system54, the steam turbine 104, the hydrocarbon production system 12, or anyother components throughout the turbine-based service system 14 or thehydrocarbon production system 12. For example, the sensor feedback 130may include temperature feedback, pressure feedback, flow rate feedback,flame temperature feedback, combustion dynamics feedback, intake oxidantcomposition feedback, intake fuel composition feedback, exhaustcomposition feedback, the output level of mechanical power 72, theoutput level of electrical power 74, the output quantity of the exhaustgas 42, 60, the output quantity or quality of the water 64, or anycombination thereof. For example, the sensor feedback 130 may include acomposition of the exhaust gas 42, 60 to facilitate stoichiometriccombustion in the SEGR gas turbine system 52. For example, the sensorfeedback 130 may include feedback from one or more intake oxidantsensors along an oxidant supply path of the oxidant 68, one or moreintake fuel sensors along a fuel supply path of the fuel 70, and one ormore exhaust emissions sensors disposed along the exhaust recirculationpath 110 and/or within the SEGR gas turbine system 52. The intakeoxidant sensors, intake fuel sensors, and exhaust emissions sensors mayinclude temperature sensors, pressure sensors, flow rate sensors, andcomposition sensors. The emissions sensors may includes sensors fornitrogen oxides (e.g., NO_(X) sensors), carbon oxides (e.g., CO sensorsand CO₂ sensors), sulfur oxides (e.g., SO_(X) sensors), hydrogen (e.g.,H₂ sensors), oxygen (e.g., O₂ sensors), unburnt hydrocarbons (e.g., HCsensors), or other products of incomplete combustion, or any combinationthereof.

Using this feedback 130, the control system 100 may adjust (e.g.,increase, decrease, or maintain) the intake flow of exhaust gas 66,oxidant 68, and/or fuel 70 into the SEGR gas turbine system 52 (amongother operational parameters) to maintain the equivalence ratio within asuitable range, e.g., between approximately 0.95 to approximately 1.05,between approximately 0.95 to approximately 1.0, between approximately1.0 to approximately 1.05, or substantially at 1.0. For example, thecontrol system 100 may analyze the feedback 130 to monitor the exhaustemissions (e.g., concentration levels of nitrogen oxides, carbon oxidessuch as CO and CO₂, sulfur oxides, hydrogen, oxygen, unburnthydrocarbons, and other products of incomplete combustion) and/ordetermine the equivalence ratio, and then control one or more componentsto adjust the exhaust emissions (e.g., concentration levels in theexhaust gas 42) and/or the equivalence ratio. The controlled componentsmay include any of the components illustrated and described withreference to the drawings, including but not limited to, valves alongthe supply paths for the oxidant 68, the fuel 70, and the exhaust gas66; an oxidant compressor, a fuel pump, or any components in the EGprocessing system 54; any components of the SEGR gas turbine system 52,or any combination thereof. The controlled components may adjust (e.g.,increase, decrease, or maintain) the flow rates, temperatures,pressures, or percentages (e.g., equivalence ratio) of the oxidant 68,the fuel 70, and the exhaust gas 66 that combust within the SEGR gasturbine system 52. The controlled components also may include one ormore gas treatment systems, such as catalyst units (e.g., oxidationcatalyst units), supplies for the catalyst units (e.g., oxidation fuel,heat, electricity, etc.), gas purification and/or separation units(e.g., solvent based separators, absorbers, flash tanks, etc.), andfiltration units. The gas treatment systems may help reduce variousexhaust emissions along the exhaust recirculation path 110, a vent path(e.g., exhausted into the atmosphere), or an extraction path to the EGsupply system 78.

In certain embodiments, the control system 100 may analyze the feedback130 and control one or more components to maintain or reduce emissionslevels (e.g., concentration levels in the exhaust gas 42, 60, 95) to atarget range, such as less than approximately 10, 20, 30, 40, 50, 100,200, 300, 400, 500, 1000, 2000, 3000, 4000, 5000, or 10000 parts permillion by volume (ppmv). These target ranges may be the same ordifferent for each of the exhaust emissions, e.g., concentration levelsof nitrogen oxides, carbon monoxide, sulfur oxides, hydrogen, oxygen,unburnt hydrocarbons, and other products of incomplete combustion. Forexample, depending on the equivalence ratio, the control system 100 mayselectively control exhaust emissions (e.g., concentration levels) ofoxidant (e.g., oxygen) within a target range of less than approximately10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 250, 500, 750, or 1000 ppmv;carbon monoxide (CO) within a target range of less than approximately20, 50, 100, 200, 500, 1000, 2500, or 5000 ppmv; and nitrogen oxides(NO_(X)) within a target range of less than approximately 50, 100, 200,300, 400, or 500 ppmv. In certain embodiments operating with asubstantially stoichiometric equivalence ratio, the control system 100may selectively control exhaust emissions (e.g., concentration levels)of oxidant (e.g., oxygen) within a target range of less thanapproximately 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100 ppmv; andcarbon monoxide (CO) within a target range of less than approximately500, 1000, 2000, 3000, 4000, or 5000 ppmv. In certain embodimentsoperating with a fuel-lean equivalence ratio (e.g., betweenapproximately 0.95 to 1.0), the control system 100 may selectivelycontrol exhaust emissions (e.g., concentration levels) of oxidant (e.g.,oxygen) within a target range of less than approximately 500, 600, 700,800, 900, 1000, 1100, 1200, 1300, 1400, or 1500 ppmv; carbon monoxide(CO) within a target range of less than approximately 10, 20, 30, 40,50, 60, 70, 80, 90, 100, 150, or 200 ppmv; and nitrogen oxides (e.g.,NO_(X)) within a target range of less than approximately 50, 100, 150,200, 250, 300, 350, or 400 ppmv. The foregoing target ranges are merelyexamples, and are not intended to limit the scope of the disclosedembodiments.

The control system 100 also may be coupled to a local interface 132 anda remote interface 134. For example, the local interface 132 may includea computer workstation disposed on-site at the turbine-based servicesystem 14 and/or the hydrocarbon production system 12. In contrast, theremote interface 134 may include a computer workstation disposedoff-site from the turbine-based service system 14 and the hydrocarbonproduction system 12, such as through an internet connection. Theseinterfaces 132 and 134 facilitate monitoring and control of theturbine-based service system 14, such as through one or more graphicaldisplays of sensor feedback 130, operational parameters, and so forth.

Again, as noted above, the controller 118 includes a variety of controls124, 126, and 128 to facilitate control of the turbine-based servicesystem 14. The steam turbine control 124 may receive the sensor feedback130 and output control commands to facilitate operation of the steamturbine 104. For example, the steam turbine control 124 may receive thesensor feedback 130 from the HRSG 56, the machinery 106, temperature andpressure sensors along a path of the steam 62, temperature and pressuresensors along a path of the water 108, and various sensors indicative ofthe mechanical power 72 and the electrical power 74. Likewise, the SEGRgas turbine system control 126 may receive sensor feedback 130 from oneor more sensors disposed along the SEGR gas turbine system 52, themachinery 106, the EG processing system 54, or any combination thereof.For example, the sensor feedback 130 may be obtained from temperaturesensors, pressure sensors, clearance sensors, vibration sensors, flamesensors, fuel composition sensors, exhaust gas composition sensors, orany combination thereof, disposed within or external to the SEGR gasturbine system 52. Finally, the machinery control 128 may receive sensorfeedback 130 from various sensors associated with the mechanical power72 and the electrical power 74, as well as sensors disposed within themachinery 106. Each of these controls 124, 126, and 128 uses the sensorfeedback 130 to improve operation of the turbine-based service system14.

In the illustrated embodiment, the SEGR gas turbine system control 126may execute instructions to control the quantity and quality of theexhaust gas 42, 60, 95 in the EG processing system 54, the EG supplysystem 78, the hydrocarbon production system 12, and/or the othersystems 84. For example, the SEGR gas turbine system control 126 maymaintain a level of oxidant (e.g., oxygen) and/or unburnt fuel in theexhaust gas 60 below a threshold suitable for use with the exhaust gasinjection EOR system 112. In certain embodiments, the threshold levelsmay be less than 1, 2, 3, 4, or 5 percent of oxidant (e.g., oxygen)and/or unburnt fuel by volume of the exhaust gas 42, 60; or thethreshold levels of oxidant (e.g., oxygen) and/or unburnt fuel (andother exhaust emissions) may be less than approximately 10, 20, 30, 40,50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, or5000 parts per million by volume (ppmv) in the exhaust gas 42, 60. Byfurther example, in order to achieve these low levels of oxidant (e.g.,oxygen) and/or unburnt fuel, the SEGR gas turbine system control 126 maymaintain an equivalence ratio for combustion in the SEGR gas turbinesystem 52 between approximately 0.95 and approximately 1.05. The SEGRgas turbine system control 126 also may control the EG extraction system80 and the EG treatment system 82 to maintain the temperature, pressure,flow rate, and gas composition of the exhaust gas 42, 60, 95 withinsuitable ranges for the exhaust gas injection EOR system 112, thepipeline 86, the storage tank 88, and the carbon sequestration system90. As discussed above, the EG treatment system 82 may be controlled topurify and/or separate the exhaust gas 42 into one or more gas streams95, such as the CO₂ rich, N₂ lean stream 96, the intermediateconcentration CO₂, N₂ stream 97, and the CO₂ lean, N₂ rich stream 98. Inaddition to controls for the exhaust gas 42, 60, and 95, the controls124, 126, and 128 may execute one or more instructions to maintain themechanical power 72 within a suitable power range, or maintain theelectrical power 74 within a suitable frequency and power range.

FIG. 3 is a diagram of embodiment of the system 10, further illustratingdetails of the SEGR gas turbine system 52 for use with the hydrocarbonproduction system 12 and/or other systems 84. In the illustratedembodiment, the SEGR gas turbine system 52 includes a gas turbine engine150 coupled to the EG processing system 54. The illustrated gas turbineengine 150 includes a compressor section 152, a combustor section 154,and an expander section or turbine section 156. The compressor section152 includes one or more exhaust gas compressors or compressor stages158, such as 1 to 20 stages of rotary compressor blades disposed in aseries arrangement. Likewise, the combustor section 154 includes one ormore combustors 160, such as 1 to 20 combustors 160 distributedcircumferentially about a rotational axis 162 of the SEGR gas turbinesystem 52. Furthermore, each combustor 160 may include one or more fuelnozzles 164 configured to inject the exhaust gas 66, the oxidant 68,and/or the fuel 70. For example, a head end portion 166 of eachcombustor 160 may house 1, 2, 3, 4, 5, 6, or more fuel nozzles 164,which may inject streams or mixtures of the exhaust gas 66, the oxidant68, and/or the fuel 70 into a combustion portion 168 (e.g., combustionchamber) of the combustor 160.

The fuel nozzles 164 may include any combination of premix fuel nozzles164 (e.g., configured to premix the oxidant 68 and fuel 70 forgeneration of an oxidant/fuel premix flame) and/or diffusion fuelnozzles 164 (e.g., configured to inject separate flows of the oxidant 68and fuel 70 for generation of an oxidant/fuel diffusion flame).Embodiments of the premix fuel nozzles 164 may include swirl vanes,mixing chambers, or other features to internally mix the oxidant 68 andfuel 70 within the nozzles 164, prior to injection and combustion in thecombustion chamber 168. The premix fuel nozzles 164 also may receive atleast some partially mixed oxidant 68 and fuel 70. In certainembodiments, each diffusion fuel nozzle 164 may isolate flows of theoxidant 68 and the fuel 70 until the point of injection, while alsoisolating flows of one or more diluents (e.g., the exhaust gas 66,steam, nitrogen, or another inert gas) until the point of injection. Inother embodiments, each diffusion fuel nozzle 164 may isolate flows ofthe oxidant 68 and the fuel 70 until the point of injection, whilepartially mixing one or more diluents (e.g., the exhaust gas 66, steam,nitrogen, or another inert gas) with the oxidant 68 and/or the fuel 70prior to the point of injection. In addition, one or more diluents(e.g., the exhaust gas 66, steam, nitrogen, or another inert gas) may beinjected into the combustor (e.g., into the hot products of combustion)either at or downstream from the combustion zone, thereby helping toreduce the temperature of the hot products of combustion and reduceemissions of NO_(X) (e.g., NO and NO₂). Regardless of the type of fuelnozzle 164, the SEGR gas turbine system 52 may be controlled to providesubstantially stoichiometric combustion of the oxidant 68 and fuel 70.

In diffusion combustion embodiments using the diffusion fuel nozzles164, the fuel 70 and oxidant 68 generally do not mix upstream from thediffusion flame, but rather the fuel 70 and oxidant 68 mix and reactdirectly at the flame surface and/or the flame surface exists at thelocation of mixing between the fuel 70 and oxidant 68. In particular,the fuel 70 and oxidant 68 separately approach the flame surface (ordiffusion boundary/interface), and then diffuse (e.g., via molecular andviscous diffusion) along the flame surface (or diffusionboundary/interface) to generate the diffusion flame. It is noteworthythat the fuel 70 and oxidant 68 may be at a substantially stoichiometricratio along this flame surface (or diffusion boundary/interface), whichmay result in a greater flame temperature (e.g., a peak flametemperature) along this flame surface. The stoichiometric fuel/oxidantratio generally results in a greater flame temperature (e.g., a peakflame temperature), as compared with a fuel-lean or fuel-richfuel/oxidant ratio. As a result, the diffusion flame may besubstantially more stable than a premix flame, because the diffusion offuel 70 and oxidant 68 helps to maintain a stoichiometric ratio (andgreater temperature) along the flame surface. Although greater flametemperatures can also lead to greater exhaust emissions, such as NO_(X)emissions, the disclosed embodiments use one or more diluents to helpcontrol the temperature and emissions while still avoiding any premixingof the fuel 70 and oxidant 68. For example, the disclosed embodimentsmay introduce one or more diluents separate from the fuel 70 and oxidant68 (e.g., after the point of combustion and/or downstream from thediffusion flame), thereby helping to reduce the temperature and reducethe emissions (e.g., NO_(X) emissions) produced by the diffusion flame.

In operation, as illustrated, the compressor section 152 receives andcompresses the exhaust gas 66 from the EG processing system 54, andoutputs a compressed exhaust gas 170 to each of the combustors 160 inthe combustor section 154. Upon combustion of the fuel 60, oxidant 68,and exhaust gas 170 within each combustor 160, additional exhaust gas orproducts of combustion 172 (i.e., combustion gas) is routed into theturbine section 156. Similar to the compressor section 152, the turbinesection 156 includes one or more turbines or turbine stages 174, whichmay include a series of rotary turbine blades. These turbine blades arethen driven by the products of combustion 172 generated in the combustorsection 154, thereby driving rotation of a shaft 176 coupled to themachinery 106. Again, the machinery 106 may include a variety ofequipment coupled to either end of the SEGR gas turbine system 52, suchas machinery 106, 178 coupled to the turbine section 156 and/ormachinery 106, 180 coupled to the compressor section 152. In certainembodiments, the machinery 106, 178, 180 may include one or moreelectrical generators, oxidant compressors for the oxidant 68, fuelpumps for the fuel 70, gear boxes, or additional drives (e.g. steamturbine 104, electrical motor, etc.) coupled to the SEGR gas turbinesystem 52. Non-limiting examples are discussed in further detail belowwith reference to TABLE 1. As illustrated, the turbine section 156outputs the exhaust gas 60 to recirculate along the exhaustrecirculation path 110 from an exhaust outlet 182 of the turbine section156 to an exhaust inlet 184 into the compressor section 152. Along theexhaust recirculation path 110, the exhaust gas 60 passes through the EGprocessing system 54 (e.g., the HRSG 56 and/or the EGR system 58) asdiscussed in detail above.

Again, each combustor 160 in the combustor section 154 receives, mixes,and stoichiometrically combusts the compressed exhaust gas 170, theoxidant 68, and the fuel 70 to produce the additional exhaust gas orproducts of combustion 172 to drive the turbine section 156. In certainembodiments, the oxidant 68 is compressed by an oxidant compressionsystem 186, such as a main oxidant compression (MOC) system (e.g., amain air compression (MAC) system) having one or more oxidantcompressors (MOCs). The oxidant compression system 186 includes anoxidant compressor 188 coupled to a drive 190. For example, the drive190 may include an electric motor, a combustion engine, or anycombination thereof. In certain embodiments, the drive 190 may be aturbine engine, such as the gas turbine engine 150. Accordingly, theoxidant compression system 186 may be an integral part of the machinery106. In other words, the compressor 188 may be directly or indirectlydriven by the mechanical power 72 supplied by the shaft 176 of the gasturbine engine 150. In such an embodiment, the drive 190 may beexcluded, because the compressor 188 relies on the power output from theturbine engine 150. However, in certain embodiments employing more thanone oxidant compressor is employed, a first oxidant compressor (e.g., alow pressure (LP) oxidant compressor) may be driven by the drive 190while the shaft 176 drives a second oxidant compressor (e.g., a highpressure (HP) oxidant compressor), or vice versa. For example, inanother embodiment, the HP MOC is driven by the drive 190 and the LPoxidant compressor is driven by the shaft 176. In the illustratedembodiment, the oxidant compression system 186 is separate from themachinery 106. In each of these embodiments, the compression system 186compresses and supplies the oxidant 68 to the fuel nozzles 164 and thecombustors 160. Accordingly, some or all of the machinery 106, 178, 180may be configured to increase the operational efficiency of thecompression system 186 (e.g., the compressor 188 and/or additionalcompressors).

The variety of components of the machinery 106, indicated by elementnumbers 106A, 106B, 106C, 106D, 106E, and 106F, may be disposed alongthe line of the shaft 176 and/or parallel to the line of the shaft 176in one or more series arrangements, parallel arrangements, or anycombination of series and parallel arrangements. For example, themachinery 106, 178, 180 (e.g., 106A through 106F) may include any seriesand/or parallel arrangement, in any order, of: one or more gearboxes(e.g., parallel shaft, epicyclic gearboxes), one or more compressors(e.g., oxidant compressors, booster compressors such as EG boostercompressors), one or more power generation units (e.g., electricalgenerators), one or more drives (e.g., steam turbine engines, electricalmotors), heat exchange units (e.g., direct or indirect heat exchangers),clutches, or any combination thereof. The compressors may include axialcompressors, radial or centrifugal compressors, or any combinationthereof, each having one or more compression stages. Regarding the heatexchangers, direct heat exchangers may include spray coolers (e.g.,spray intercoolers), which inject a liquid spray into a gas flow (e.g.,oxidant flow) for direct cooling of the gas flow. Indirect heatexchangers may include at least one wall (e.g., a shell and tube heatexchanger) separating first and second flows, such as a fluid flow(e.g., oxidant flow) separated from a coolant flow (e.g., water, air,refrigerant, or any other liquid or gas coolant), wherein the coolantflow transfers heat from the fluid flow without any direct contact.Examples of indirect heat exchangers include intercooler heat exchangersand heat recovery units, such as heat recovery steam generators. Theheat exchangers also may include heaters. As discussed in further detailbelow, each of these machinery components may be used in variouscombinations as indicated by the non-limiting examples set forth inTABLE 1.

Generally, the machinery 106, 178, 180 may be configured to increase theefficiency of the compression system 186 by, for example, adjustingoperational speeds of one or more oxidant compressors in the system 186,facilitating compression of the oxidant 68 through cooling, and/orextraction of surplus power. The disclosed embodiments are intended toinclude any and all permutations of the foregoing components in themachinery 106, 178, 180 in series and parallel arrangements, whereinone, more than one, all, or none of the components derive power from theshaft 176. As illustrated below, TABLE 1 depicts some non-limitingexamples of arrangements of the machinery 106, 178, 180 disposedproximate and/or coupled to the compressor and turbine sections 152,156.

TABLE 1 106A 106B 106C 106D 106E 106F MOC GEN MOC GBX GEN LP HP GEN MOCMOC HP GBX LP GEN MOC MOC MOC GBX GEN MOC HP GBX GEN LP MOC MOC MOC GBXGEN MOC GBX DRV DRV GBX LP HP GBX GEN MOC MOC DRV GBX HP LP GEN MOC MOCHP GBX LP GEN MOC CLR MOC HP GBX LP GBX GEN MOC CLR MOC HP GBX LP GENMOC HTR MOC STGN MOC GEN DRV MOC DRV GEN DRV MOC GEN DRV CLU MOC GEN DRVCLU MOC GBX GEN

As illustrated above in TABLE 1, a cooling unit is represented as CLR, aclutch is represented as CLU, a drive is represented by DRV, a gearboxis represented as GBX, a generator is represented by GEN, a heating unitis represented by HTR, a main oxidant compressor unit is represented byMOC, with low pressure and high pressure variants being represented asLP MOC and HP MOC, respectively, and a steam generator unit isrepresented as STGN. Although TABLE 1 illustrates the machinery 106,178, 180 in sequence toward the compressor section 152 or the turbinesection 156, TABLE 1 is also intended to cover the reverse sequence ofthe machinery 106, 178, 180. In TABLE 1, any cell including two or morecomponents is intended to cover a parallel arrangement of thecomponents. TABLE 1 is not intended to exclude any non-illustratedpermutations of the machinery 106, 178, 180. These components of themachinery 106, 178, 180 may enable feedback control of temperature,pressure, and flow rate of the oxidant 68 sent to the gas turbine engine150. As discussed in further detail below, the oxidant 68 and the fuel70 may be supplied to the gas turbine engine 150 at locationsspecifically selected to facilitate isolation and extraction of thecompressed exhaust gas 170 without any oxidant 68 or fuel 70 degradingthe quality of the exhaust gas 170.

The EG supply system 78, as illustrated in FIG. 3, is disposed betweenthe gas turbine engine 150 and the target systems (e.g., the hydrocarbonproduction system 12 and the other systems 84). In particular, the EGsupply system 78, e.g., the EG extraction system (EGES) 80), may becoupled to the gas turbine engine 150 at one or more extraction points76 along the compressor section 152, the combustor section 154, and/orthe turbine section 156. For example, the extraction points 76 may belocated between adjacent compressor stages, such as 2, 3, 4, 5, 6, 7, 8,9, or 10 interstage extraction points 76 between compressor stages. Eachof these interstage extraction points 76 provides a differenttemperature and pressure of the extracted exhaust gas 42. Similarly, theextraction points 76 may be located between adjacent turbine stages,such as 2, 3, 4, 5, 6, 7, 8, 9, or 10 interstage extraction points 76between turbine stages. Each of these interstage extraction points 76provides a different temperature and pressure of the extracted exhaustgas 42. By further example, the extraction points 76 may be located at amultitude of locations throughout the combustor section 154, which mayprovide different temperatures, pressures, flow rates, and gascompositions. Each of these extraction points 76 may include an EGextraction conduit, one or more valves, sensors, and controls, which maybe used to selectively control the flow of the extracted exhaust gas 42to the EG supply system 78.

The extracted exhaust gas 42, which is distributed by the EG supplysystem 78, has a controlled composition suitable for the target systems(e.g., the hydrocarbon production system 12 and the other systems 84).For example, at each of these extraction points 76, the exhaust gas 170may be substantially isolated from injection points (or flows) of theoxidant 68 and the fuel 70. In other words, the EG supply system 78 maybe specifically designed to extract the exhaust gas 170 from the gasturbine engine 150 without any added oxidant 68 or fuel 70. Furthermore,in view of the stoichiometric combustion in each of the combustors 160,the extracted exhaust gas 42 may be substantially free of oxygen andfuel. The EG supply system 78 may route the extracted exhaust gas 42directly or indirectly to the hydrocarbon production system 12 and/orother systems 84 for use in various processes, such as enhanced oilrecovery, carbon sequestration, storage, or transport to an offsitelocation. However, in certain embodiments, the EG supply system 78includes the EG treatment system (EGTS) 82 for further treatment of theexhaust gas 42, prior to use with the target systems. For example, theEG treatment system 82 may purify and/or separate the exhaust gas 42into one or more streams 95, such as the CO₂ rich, N₂ lean stream 96,the intermediate concentration CO₂, N₂ stream 97, and the CO₂ lean, N₂rich stream 98. These treated exhaust gas streams 95 may be usedindividually, or in any combination, with the hydrocarbon productionsystem 12 and the other systems 84 (e.g., the pipeline 86, the storagetank 88, and the carbon sequestration system 90).

Similar to the exhaust gas treatments performed in the EG supply system78, the EG processing system 54 may include a plurality of exhaust gas(EG) treatment components 192, such as indicated by element numbers 194,196, 198, 200, 202, 204, 206, 208, and 210. These EG treatmentcomponents 192 (e.g., 194 through 210) may be disposed along the exhaustrecirculation path 110 in one or more series arrangements, parallelarrangements, or any combination of series and parallel arrangements.For example, the EG treatment components 192 (e.g., 194 through 210) mayinclude any series and/or parallel arrangement, in any order, of: one ormore heat exchangers (e.g., heat recovery units such as heat recoverysteam generators, condensers, coolers, or heaters), catalyst systems(e.g., oxidation catalyst systems), particulate and/or water removalsystems (e.g., inertial separators, coalescing filters, waterimpermeable filters, and other filters), chemical injection systems,solvent based treatment systems (e.g., absorbers, flash tanks, etc.),carbon capture systems, gas separation systems, gas purificationsystems, and/or a solvent based treatment system, or any combinationthereof. In certain embodiments, the catalyst systems may include anoxidation catalyst, a carbon monoxide reduction catalyst, a nitrogenoxides reduction catalyst, an aluminum oxide, a zirconium oxide, asilicone oxide, a titanium oxide, a platinum oxide, a palladium oxide, acobalt oxide, or a mixed metal oxide, or a combination thereof. Thedisclosed embodiments are intended to include any and all permutationsof the foregoing components 192 in series and parallel arrangements. Asillustrated below, TABLE 2 depicts some non-limiting examples ofarrangements of the components 192 along the exhaust recirculation path110.

TABLE 2 194 196 198 200 202 204 206 208 210 CU HRU BB MRU PRU CU HRU HRUBB MRU PRU DIL CU HRSG HRSG BB MRU PRU OCU HRU OCU HRU OCU BB MRU PRUHRU HRU BB MRU PRU CU CU HRSG HRSG BB MRU PRU DIL OCU OCU OCU HRSG OCUHRSG OCU BB MRU PRU DIL OCU OCU OCU HRSG HRSG BB COND INER WFIL CFIL DILST ST OCU OCU BB COND INER FIL DIL HRSG HRSG ST ST OCU HRSG HRSG OCU BBMRU MRU PRU PRU ST ST HE WFIL INER FIL COND CFIL CU HRU HRU HRU BB MRUPRU PRU DIL COND COND COND HE INER FIL COND CFIL WFIL

As illustrated above in TABLE 2, a catalyst unit is represented by CU,an oxidation catalyst unit is represented by OCU, a booster blower isrepresented by BB, a heat exchanger is represented by HX, a heatrecovery unit is represented by HRU, a heat recovery steam generator isrepresented by HRSG, a condenser is represented by COND, a steam turbineis represented by ST, a particulate removal unit is represented by PRU,a moisture removal unit is represented by MRU, a filter is representedby FIL, a coalescing filter is represented by CFIL, a water impermeablefilter is represented by WFIL, an inertial separator is represented byINER, and a diluent supply system (e.g., steam, nitrogen, or other inertgas) is represented by DIL. Although TABLE 2 illustrates the components192 in sequence from the exhaust outlet 182 of the turbine section 156toward the exhaust inlet 184 of the compressor section 152, TABLE 2 isalso intended to cover the reverse sequence of the illustratedcomponents 192. In TABLE 2, any cell including two or more components isintended to cover an integrated unit with the components, a parallelarrangement of the components, or any combination thereof. Furthermore,in context of TABLE 2, the HRU, the HRSG, and the COND are examples ofthe HE; the HRSG is an example of the HRU; the COND, WFIL, and CFIL areexamples of the WRU; the INER, FIL, WFIL, and CFIL are examples of thePRU; and the WFIL and CFIL are examples of the FIL. Again, TABLE 2 isnot intended to exclude any non-illustrated permutations of thecomponents 192. In certain embodiments, the illustrated components 192(e.g., 194 through 210) may be partially or completed integrated withinthe HRSG 56, the EGR system 58, or any combination thereof. These EGtreatment components 192 may enable feedback control of temperature,pressure, flow rate, and gas composition, while also removing moistureand particulates from the exhaust gas 60. Furthermore, the treatedexhaust gas 60 may be extracted at one or more extraction points 76 foruse in the EG supply system 78 and/or recirculated to the exhaust inlet184 of the compressor section 152.

As the treated, recirculated exhaust gas 66 passes through thecompressor section 152, the SEGR gas turbine system 52 may bleed off aportion of the compressed exhaust gas along one or more lines 212 (e.g.,bleed conduits or bypass conduits). Each line 212 may route the exhaustgas into one or more heat exchangers 214 (e.g., cooling units), therebycooling the exhaust gas for recirculation back into the SEGR gas turbinesystem 52. For example, after passing through the heat exchanger 214, aportion of the cooled exhaust gas may be routed to the turbine section156 along line 212 for cooling and/or sealing of the turbine casing,turbine shrouds, bearings, and other components. In such an embodiment,the SEGR gas turbine system 52 does not route any oxidant 68 (or otherpotential contaminants) through the turbine section 156 for coolingand/or sealing purposes, and thus any leakage of the cooled exhaust gaswill not contaminate the hot products of combustion (e.g., workingexhaust gas) flowing through and driving the turbine stages of theturbine section 156. By further example, after passing through the heatexchanger 214, a portion of the cooled exhaust gas may be routed alongline 216 (e.g., return conduit) to an upstream compressor stage of thecompressor section 152, thereby improving the efficiency of compressionby the compressor section 152. In such an embodiment, the heat exchanger214 may be configured as an interstage cooling unit for the compressorsection 152. In this manner, the cooled exhaust gas helps to increasethe operational efficiency of the SEGR gas turbine system 52, whilesimultaneously helping to maintain the purity of the exhaust gas (e.g.,substantially free of oxidant and fuel).

FIG. 4 is a flow chart of an embodiment of an operational process 220 ofthe system 10 illustrated in FIGS. 1-3. In certain embodiments, theprocess 220 may be a computer implemented process, which accesses one ormore instructions stored on the memory 122 and executes the instructionson the processor 120 of the controller 118 shown in FIG. 2. For example,each step in the process 220 may include instructions executable by thecontroller 118 of the control system 100 described with reference toFIG. 2.

The process 220 may begin by initiating a startup mode of the SEGR gasturbine system 52 of FIGS. 1-3, as indicated by block 222. For example,the startup mode may involve a gradual ramp up of the SEGR gas turbinesystem 52 to maintain thermal gradients, vibration, and clearance (e.g.,between rotating and stationary parts) within acceptable thresholds. Forexample, during the startup mode 222, the process 220 may begin tosupply a compressed oxidant 68 to the combustors 160 and the fuelnozzles 164 of the combustor section 154, as indicated by block 224. Incertain embodiments, the compressed oxidant may include a compressedair, oxygen, oxygen-enriched air, oxygen-reduced air, oxygen-nitrogenmixtures, or any combination thereof. For example, the oxidant 68 may becompressed by the oxidant compression system 186 illustrated in FIG. 3.The process 220 also may begin to supply fuel to the combustors 160 andthe fuel nozzles 164 during the startup mode 222, as indicated by block226. During the startup mode 222, the process 220 also may begin tosupply exhaust gas (as available) to the combustors 160 and the fuelnozzles 164, as indicated by block 228. For example, the fuel nozzles164 may produce one or more diffusion flames, premix flames, or acombination of diffusion and premix flames. During the startup mode 222,the exhaust gas 60 being generated by the gas turbine engine 156 may beinsufficient or unstable in quantity and/or quality. Accordingly, duringthe startup mode, the process 220 may supply the exhaust gas 66 from oneor more storage units (e.g., storage tank 88), the pipeline 86, otherSEGR gas turbine systems 52, or other exhaust gas sources.

The process 220 may then combust a mixture of the compressed oxidant,fuel, and exhaust gas in the combustors 160 to produce hot combustiongas 172, as indicated by block 230. In particular, the process 220 maybe controlled by the control system 100 of FIG. 2 to facilitatestoichiometric combustion (e.g., stoichiometric diffusion combustion,premix combustion, or both) of the mixture in the combustors 160 of thecombustor section 154. However, during the startup mode 222, it may beparticularly difficult to maintain stoichiometric combustion of themixture (and thus low levels of oxidant and unburnt fuel may be presentin the hot combustion gas 172). As a result, in the startup mode 222,the hot combustion gas 172 may have greater amounts of residual oxidant68 and/or fuel 70 than during a steady state mode as discussed infurther detail below. For this reason, the process 220 may execute oneor more control instructions to reduce or eliminate the residual oxidant68 and/or fuel 70 in the hot combustion gas 172 during the startup mode.

The process 220 then drives the turbine section 156 with the hotcombustion gas 172, as indicated by block 232. For example, the hotcombustion gas 172 may drive one or more turbine stages 174 disposedwithin the turbine section 156. Downstream of the turbine section 156,the process 220 may treat the exhaust gas 60 from the final turbinestage 174, as indicated by block 234. For example, the exhaust gastreatment 234 may include filtration, catalytic reaction of any residualoxidant 68 and/or fuel 70, chemical treatment, heat recovery with theHRSG 56, and so forth. The process 220 may also recirculate at leastsome of the exhaust gas 60 back to the compressor section 152 of theSEGR gas turbine system 52, as indicated by block 236. For example, theexhaust gas recirculation 236 may involve passage through the exhaustrecirculation path 110 having the EG processing system 54 as illustratedin FIGS. 1-3.

In turn, the recirculated exhaust gas 66 may be compressed in thecompressor section 152, as indicated by block 238. For example, the SEGRgas turbine system 52 may sequentially compress the recirculated exhaustgas 66 in one or more compressor stages 158 of the compressor section152. Subsequently, the compressed exhaust gas 170 may be supplied to thecombustors 160 and fuel nozzles 164, as indicated by block 228. Steps230, 232, 234, 236, and 238 may then repeat, until the process 220eventually transitions to a steady state mode, as indicated by block240. Upon the transition 240, the process 220 may continue to performthe steps 224 through 238, but may also begin to extract the exhaust gas42 via the EG supply system 78, as indicated by block 242. For example,the exhaust gas 42 may be extracted from one or more extraction points76 along the compressor section 152, the combustor section 154, and theturbine section 156 as indicated in FIG. 3. In turn, the process 220 maysupply the extracted exhaust gas 42 from the EG supply system 78 to thehydrocarbon production system 12, as indicated by block 244. Thehydrocarbon production system 12 may then inject the exhaust gas 42 intothe earth 32 for enhanced oil recovery, as indicated by block 246. Forexample, the extracted exhaust gas 42 may be used by the exhaust gasinjection EOR system 112 of the EOR system 18 illustrated in FIGS. 1-3.

FIG. 5 is a schematic diagram of an embodiment of a SEGR oxidantcompressor system 260. Elements in FIG. 5 in common with those shown inprevious figures are labeled with the same reference numerals. In theillustrated embodiment, the oxidant 68 enters an inlet 262 of theoxidant compressor 188 (e.g., main air compressor or MAC). In certainembodiments, the oxidant 68 may be conveyed to the oxidant compressor188 via an oxidant inlet conduit 263. The oxidant compressor 188compresses the oxidant 68 to produce compressed oxidant 264 that exitsan outlet 266 of the oxidant compressor 188. The oxidant 68 entering theinlet 262 of the oxidant compressor 188 may pass through a series ofinlet guide vanes (IGVs) 268, which controls the amount of the oxidant68 that is conveyed into the oxidant compressor 188. The IGVs 268 may bedisposed at an angle that may be increased or decreased to allow less ormore oxidant 68 into the oxidant compressor 188. For example, an IGVactuator 270 may be coupled to the IGVs 268 to adjust the angle of theIGVs 268. In certain embodiments, the control system 100 may send anoutput signal 272 to the IGV actuator 270 to adjust the angle of theIGVs 268.

As shown in FIG. 5, the SEGR oxidant compressor system 260 may includean inlet oxidant heating system 274, which may be used to route aheating gas 276 to the inlet 262 of the oxidant compressor 188. Theheating gas 276 may include any gas within the SEGR gas turbine system52 at a temperature and pressure suitable for heating the oxidant 68(e.g., exhaust gas, carbon dioxide captured from exhaust gas), butexcludes the compressed oxidant 264. In other words, the heating gas 276does not include the compressed oxidant 264 exiting directly from theoutlet 266 of the oxidant compressor 188, which may be used with otherinlet bleed heat (IBH) techniques. Specific examples of the heating gas276 are described in detail below. As shown in FIG. 5, an inlet oxidantheating control valve 278 may be used to adjust a flow rate of theheating gas 276. As such, the inlet oxidant heating control valve 278may receive the output signal 272 from the control system 100. Forexample, the output signal 272 to the oxidant heating control valve 278may be based on the sensor feedback 130 from one or more sensors 280disposed throughout the SEGR oxidant compressor system 260. In certainembodiments, the one or more sensors 280 may provide sensor feedback 130indicative of conditions at the inlet 262, within the oxidant compressor188, and/or at the outlet 266. For example, the sensor feedback 130 mayinclude an inlet temperature of oxidant compressor 188, a differentialpressure of the oxidant compressor 188, a total inlet flow rate of theoxidant compressor 188, or an efficiency of the oxidant compressor 188,or any combination thereof. If the sensor feedback 130 indicates thatless heating of the oxidant 68 is desired, the control system 100 maysend the output signal 272 to the oxidant heating control valve 278 toreduce the flow rate of the heating gas 276 to the inlet 262.Alternatively, if the sensor feedback 130 indicates that additionalheating of the oxidant 68 is desired, the control system 100 may sendthe output signal 272 to the oxidant heating control valve 278 toincrease the flow rate of the heating gas 276 to the inlet 262. In someembodiments, the SEGR oxidant compressor system 260 may include aplurality of sources for the heating gas 276, as described in detailbelow, each source with its own control valve 278. In such embodiments,the plurality of control valves 278 may be used to control which of thesources of heating gas 276 are used for a particular situation. Forexample, the physical properties (e.g., temperature, pressure, orcomposition) of the heating gas 276 from each of the plurality ofsources may differ from one another. As such, a particular source ofheating gas 276 (e.g., a relatively hotter heating gas 276) may be usedin certain situations (e.g., startup) and another source of heating gas276 (e.g., a relatively cooler heating gas 276) may be used in othersituations (e.g., normal operation). In certain embodiments, a mixer 282may be used to combine the oxidant 68 with the heating gas 276 enteringthe inlet 262 of the oxidant compressor 188. In other words, the oxidant68 is being directly mixed with the heating gas 276 (e.g., exhaust gas).Thus, the mixer 282 may be used to help increase the uniformity of thetemperature of the oxidant 68 and the heating gas 276 entering the inlet262.

Use of the inlet oxidant heating system 274 with the SEGR oxidantcompressor system 260 may provide several benefits compared tocompressor systems that do not include the inlet oxidant heating system274. For example, the heating gas 276 may be warmer than the oxidant 68.Thus, the mixture of the heating gas 276 and the oxidant 68 provided tothe inlet 262 by the inlet oxidant heating system 274 may be warmer thanthe oxidant 68 alone, thereby reducing the possibility of icing of theoxidant compressor 188. In addition, use of the inlet oxidant heatingsystem 274 may enable the IGVs 268 to be operated in a more openposition than without use of the inlet oxidant heating system 274,thereby reducing the possibility of surging of the oxidant compressor188. The inlet oxidant heating system 274 may be used to adjust a flowrate of the heating gas 276 to maintain an angle of the IGVs 268 withina desired range. This means that use of the inlet oxidant heating system274 may provide operators an additional method for adjusting a totalinlet flow rate of the oxidant compressor 188. In other words, if theoperators desire the total inlet flow rate of the oxidant compressor 188to be decreased at a given IGV position, the inlet oxidant heatingsystem 274 may be used to add additional heating gas 276 to the inlet262. In addition, the inlet oxidant heating system 274 may be used toadjust an efficiency of the oxidant compressor 188. Specifically, byincreasing the inlet flow rate of the oxidant compressor 188, the IGVs268 may open further, thereby increasing the efficiency of the oxidantcompressor 188. Moreover, the addition of the exhaust gas (e.g., heatinggas 276) with the oxidant 68 may help increase production of carbondioxide because of the increased amount of recirculated exhaust gas.

FIG. 6 is a schematic diagram of the SEGR gas turbine system 52 thatincludes an embodiment of the inlet oxidant heating system 274. Elementsin FIG. 6 in common with those shown in previous figures are labeledwith the same reference numerals. In the illustrated embodiment, theexhaust gas 60 flows along the exhaust recirculation path 110 to theHRSG 56 to generate steam. The exhaust gas 60 from the HRSG 56 may thenflow to an exhaust gas blower 300, which may increase a pressure of theexhaust gas 60. For example, the exhaust gas blower 300 may be acompressor or fan. The compressed exhaust gas 60 from the exhaust gasblower 300 may then flow to an exhaust gas cooler 302, which may reducea temperature of the exhaust gas 60. For example, the exhaust gas cooler302 may use a fluid, such as a liquid or a gas, to cool the exhaust gas60. In one embodiment, the exhaust gas cooler 302 may use water to coolthe exhaust gas 60. The cooled exhaust gas 66 may then flow along theexhaust recirculation path 110 to the compressor section 152.

As shown in FIG. 6, a portion of the exhaust gas 60 may be used as theheating gas 276 for the inlet oxidant hating system 274. Specifically,an inlet oxidant heating conduit 304 may convey the exhaust gas 60 tothe inlet exhaust gas control valve 278. As shown in FIG. 6, the inletoxidant heating conduit 304 is coupled to the oxidant inlet conduit 263.In the illustrated embodiment, the inlet oxidant heating conduit 304 iscoupled between the exhaust gas blower 300 and the exhaust gas cooler302 so that the increased pressure of the exhaust gas 60 discharged fromthe exhaust gas blower 300 is used to overcome pressure lossesassociated with the inlet exhaust gas heating conduit 304, therebyenabling the exhaust gas 60 to enter the oxidant compressor 188. Inaddition, as the exhaust gas 60 upstream of the exhaust gas cooler 302has not been cooled by the exhaust gas cooler 302, the exhaust gas 60may be well suited for heating the oxidant 68 and reducing icing and/orsurging of the oxidant compressor 188. In some embodiments, othersources of heating gas 276 other than that shown in FIG. 6 may be usedwith control valves 278 for each source.

FIG. 7 is a schematic diagram of an embodiment of the inlet oxidantheating system 274 with a plurality of sources for heating gas 276(e.g., “HG”). For example, in one embodiment, an intercooler 320 may bedisposed downstream of the oxidant compressor 188 to cool the compressedoxidant 264. The inlet oxidant heating conduit 304 may be coupleddownstream of the intercooler 320 to convey the compressed oxidant 264to the inlet 262 of the oxidant compressor 188. In another embodiment, abooster oxidant compressor 322 may be disposed downstream of the oxidantcompressor 188 and/or downstream of the intercooler 320 to furthercompress the compressed oxidant 264 that is then routed to the turbinecombustor 160. The inlet oxidant heating conduit 304 may be coupleddownstream of the booster oxidant compressor 322 and may convey thecompressed oxidant 264 to the inlet 262 of the oxidant compressor 188.In other embodiments, the inlet oxidant heating conduit 304 may becoupled to various locations within the SEGR gas turbine system 52 toconvey combustion products and/or exhaust gas to the inlet 262 of theoxidant compressor 188. For example, the inlet oxidant heating conduit304 may be coupled to at least one of the exhaust inlet 184 of thecompressor section 152, a compressor outlet 324 of the compressorsection 152, one or more compressor stages 158, one or more turbinecombustors 160, a turbine inlet 326 of the turbine section 156, one ormore turbine stages 174, the exhaust outlet 182, or the exhaust gasprocessing system 54, or any combination thereof. In some embodiments,the sources of the heating gas 276 may be in other gas turbine systems(e.g., a second, third, or fourth gas turbine engine in a parallel gasturbine system train), other combustion systems, and so forth.

As described above, certain embodiments of the SEGR gas turbine system52 may include the oxidant compressor 188 and the gas turbine engine150. The gas turbine engine 150 may include the combustor section 154having the turbine combustor 160, the turbine section 156 driven bycombustion products from the turbine combustor 160, and the compressorsection 152 driven by the turbine section 156. The compressor section152 compresses and routes the compressed exhaust gas 170 to the turbinecombustor 160, and the oxidant compressor 188 compresses and routes theoxidant 68 to the turbine combustor 160. The inlet oxidant heatingsystem 274 may route at least one of the portion of the compressedexhaust 170, or the portion of the exhaust gas 60, or any combinationthereof (e.g., the heating gas 276), to the inlet 262 of the oxidantcompressor 188. As the temperature of the gas provided by the inletoxidant heating system 274 may be greater than the temperature of theoxidant 68 in certain situations, the inlet oxidant heating system 274may help reduce icing and/or surging of the oxidant compressor 188. Insome embodiments, there may be a plurality of sources for the heatinggas 276, each of which may differ in properties from one another, andthe control system 100 may be used to select a desired source of heatinggas 276. Each source of heating gas 276 may have its own control valve278 to provide enhanced flexibility for the control system 100.

Additional Description

The present embodiments provide a system and method for gas turbineengines. It should be noted that any one or a combination of thefeatures described above may be utilized in any suitable combination.Indeed, all permutations of such combinations are presentlycontemplated. By way of example, the following clauses are offered asfurther description of the present disclosure:

Embodiment 1

A system, comprising: an oxidant compressor; and a gas turbine engine,comprising: a combustor section having a turbine combustor; a turbinedriven by combustion products from the turbine combustor; an exhaust gascompressor driven by the turbine, wherein the exhaust gas compressor isconfigured to compress and route an exhaust flow to the turbinecombustor, and the oxidant compressor is configured to compress androute an oxidant flow to the turbine combustor; and an inlet oxidantheating system configured to route at least one of a first portion ofthe combustion products, or a second portion of the exhaust flow, or anycombination thereof, to an inlet of the oxidant compressor.

Embodiment 2

The system of embodiment 1, wherein the inlet oxidant heating system isconfigured to combine an oxidant inlet flow to the oxidant compressorwith the at least one of the first portion of the combustion products,or the second portion of the exhaust flow, or any combination thereof.

Embodiment 3

The system defined in any preceding embodiment, wherein the inletoxidant heating system is configured to at least one of reduce icing ofthe oxidant compressor, reduce surging of the oxidant compressor, adjusta total inlet flow rate of the oxidant compressor, or adjust anefficiency of the oxidant compressor, or any combination thereof.

Embodiment 4

The system defined in any preceding embodiment, wherein the inletoxidant heating system comprises an inlet oxidant heating conduitconfigured to convey the at least one of the first portion of thecombustion products, or the second portion of the exhaust flow, or anycombination thereof, to the inlet of the oxidant compressor.

Embodiment 5

The system defined in any preceding embodiment, comprising: an exhaustgas blower configured to increase a pressure of the exhaust flow fromthe turbine; and an exhaust gas cooler configured to cool the exhaustflow from the exhaust gas blower, wherein the inlet oxidant heatingconduit is coupled between the exhaust gas blower and the exhaust gascooler.

Embodiment 6

The system defined in any preceding embodiment, comprising a heatrecovery steam generator (HRSG) disposed upstream of the exhaust gasblower, wherein the HRSG is configured to generate steam from theexhaust flow from the turbine.

Embodiment 7

The system defined in any preceding embodiment, comprising anintercooler configured to cool the oxidant flow from the oxidantcompressor, wherein the inlet oxidant heating conduit is coupleddownstream of the intercooler and is configured to convey a thirdportion of the oxidant flow to the inlet of the oxidant compressor.

Embodiment 8

The system defined in any preceding embodiment, comprising a boosteroxidant compressor configured to compress the oxidant flow from theoxidant compressor, wherein the inlet oxidant heating conduit is coupleddownstream of the booster oxidant compressor and is configured to conveya fourth portion of the oxidant flow to the inlet of the oxidantcompressor.

Embodiment 9

The system defined in any preceding embodiment, wherein the inletoxidant heating conduit is coupled to at least one of a compressor inletof the exhaust gas compressor, a compressor outlet of the exhaust gascompressor, a compressor stage of the exhaust gas compressor, theturbine combustor, a turbine inlet of the turbine, a turbine stage ofthe turbine, a turbine outlet of the turbine, an exhaust gas processingsystem, a second gas turbine engine, or a combustion system, or anycombination thereof.

Embodiment 10

The system defined in any preceding embodiment, comprising an oxidantinlet conduit configured to convey an inlet oxidant flow to the inlet ofthe oxidant compressor, wherein the inlet oxidant heating conduit iscoupled to the oxidant inlet conduit.

Embodiment 11

The system defined in any preceding embodiment, wherein the inletoxidant heating system comprises an inlet oxidant heating control valveconfigured to adjust a flow rate of the at least one of the firstportion of the combustion products, or the second portion of the exhaustflow, or any combination thereof, to the inlet of the oxidantcompressor.

Embodiment 12

The system defined in any preceding embodiment, comprising a sensorconfigured to provide a signal indicative of at least one of an inlettemperature of oxidant compressor, a differential pressure of theoxidant compressor, a total inlet flow rate of the oxidant compressor,or an efficiency of the oxidant compressor, or any combination thereof,to a control system.

Embodiment 13

The system defined in any preceding embodiment, comprising the controlsystem configured to adjust the inlet oxidant heating control valve inresponse to the signal from the sensor.

Embodiment 14

The system defined in any preceding embodiment, wherein the inletoxidant heating system is configured to adjust a flow rate of at leastone of the first portion of the combustion products, or the secondportion of the exhaust flow, or any combination thereof, to maintain anangle of an inlet guide vane within a range, wherein the inlet guidevane is coupled to the inlet of the oxidant compressor and is configuredto adjust a total inlet flow rate of the oxidant compressor.

Embodiment 15

The system defined in any preceding embodiment, comprising an exhaustgas extraction system coupled to the gas turbine engine, and ahydrocarbon production system coupled to the exhaust gas extractionsystem.

Embodiment 16

The system defined in any preceding embodiment, wherein the gas turbineengine is a stoichiometric exhaust gas recirculation (SEGR) gas turbineengine.

Embodiment 17

A method, comprising: driving a turbine of a gas turbine engine withcombustion products from a turbine combustor; driving an exhaust gascompressor using the turbine; compressing and routing an exhaust flow tothe turbine combustor using the exhaust gas compressor; compressing androuting an oxidant flow to the turbine combustor using an oxidantcompressor; and routing at least one of a first portion of thecombustion products, or a second portion of the exhaust flow, or anycombination thereof, to an inlet of the oxidant compressor.

Embodiment 18

The method or system defined in any preceding embodiment, comprisingmixing an oxidant inlet flow to the oxidant compressor with the at leastone of the first portion of the combustion products, or the secondportion of the exhaust flow, or any combination thereof using a mixer.

Embodiment 19

The method or system defined in any preceding embodiment, comprising atleast one of reducing icing of the oxidant compressor, reducing surgingof the oxidant compressor, adjusting a total inlet flow rate of theoxidant compressor, or adjusting an efficiency of the oxidantcompressor, or any combination thereof, using the inlet oxidant heatingsystem.

Embodiment 20

The method or system defined in any preceding embodiment, comprisingconveying the at least one of the first portion of the combustionproducts, or the second portion of the exhaust flow, or any combinationthereof, to the inlet of the oxidant compressor using an inlet oxidantheating conduit.

Embodiment 21

The method or system defined in any preceding embodiment, comprising:increasing a pressure of the exhaust flow from the turbine using anexhaust gas blower; cooling the exhaust flow from the exhaust gas blowerusing an exhaust gas cooler; and routing the second portion of thecombustion products from the exhaust gas blower to the inlet of theoxidant compressor using the inlet oxidant heating conduit.

Embodiment 22

The method or system defined in any preceding embodiment, comprisingrouting the second portion of the exhaust flow from a heat recoverysteam generator (HRSG) to the inlet of the oxidant compressor using theinlet oxidant heating conduit.

Embodiment 23

The method or system defined in any preceding embodiment, comprisingrouting a third portion of the oxidant flow from an intercooler to theinlet of the oxidant compressor using the inlet oxidant heating conduit,wherein the intercooler is configured to cool the oxidant flow from theoxidant compressor.

Embodiment 24

The method or system defined in any preceding embodiment, comprisingrouting a fourth portion of the oxidant flow from a booster oxidantcompressor to the inlet of the oxidant compressor using the inletoxidant heating conduit, wherein the booster oxidant compressor isconfigured to compress the oxidant flow from the oxidant compressor.

Embodiment 25

The method or system defined in any preceding embodiment, comprisingrouting at least one of the first portion of the combustion products, orthe second portion of the exhaust flow, or any combination thereof, fromat least one of a compressor inlet of the exhaust gas compressor, acompressor outlet of the exhaust gas compressor, a compressor stage ofthe exhaust gas compressor, the turbine combustor, a turbine inlet ofthe turbine, a turbine stage of the turbine, a turbine outlet of theturbine, an exhaust gas processing system, a second gas turbine engine,or a combustion system, or any combination thereof, using the inletoxidant heating conduit.

Embodiment 26

The method or system defined in any preceding embodiment, comprising:routing an inlet oxidant flow to the inlet of the oxidant compressorusing an oxidant inlet conduit; and routing the at least one of thefirst portion of the combustion products, or the second portion of theexhaust flow, or any combination thereof, from the inlet oxidant heatingconduit to the oxidant inlet conduit.

Embodiment 27

The method or system defined in any preceding embodiment, comprisingadjusting a flow rate of the at least one of the first portion of thecombustion products, or the second portion of the exhaust flow, or anycombination thereof, using an inlet oxidant heating control valve.

Embodiment 28

The method or system defined in any preceding embodiment, comprisingproviding a signal indicative of at least one of an inlet temperature ofoxidant compressor, a differential pressure of the oxidant compressor, atotal inlet flow rate of the oxidant compressor, or an efficiency of theoxidant compressor, or any combination thereof, from a sensor to acontrol system.

Embodiment 29

The method or system defined in any preceding embodiment, comprisingadjusting the inlet oxidant heating control valve in response to thesignal from the sensor using the control system.

Embodiment 30

The method or system defined in any preceding embodiment, comprisingadjusting a flow rate of at least one of the first portion of thecombustion products, or the second portion of the exhaust flow, or anycombination thereof, using the inlet oxidant heating system to maintainan angle of an inlet guide vane within a range, wherein the inlet guidevane is coupled to the inlet of the oxidant compressor and is configuredto adjust a total inlet flow rate of the oxidant compressor.

Embodiment 31

A system, comprising: instructions disposed on a non-transitory, machinereadable medium, wherein the instructions are configured to monitor orcontrol operations to: drive a turbine of a gas turbine engine withcombustion products from a turbine combustor; drive an exhaust gascompressor using the turbine; compress and route an exhaust flow to theturbine combustor using the exhaust gas compressor; compress and routean oxidant flow to the turbine combustor using an oxidant compressor;and route at least one of a first portion of the combustion products, ora second portion of the exhaust flow, or any combination thereof, to aninlet of the oxidant compressor.

Embodiment 32

The method or system defined in any preceding embodiment, wherein theinstructions are configured to monitor or control operations to mix anoxidant inlet flow to the oxidant compressor with the at least one ofthe first portion of the combustion products, or the second portion ofthe exhaust flow, or any combination thereof using a mixer.

Embodiment 33

The method or system defined in any preceding embodiment, wherein theinstructions are configured to monitor or control operations to at leastone of reduce icing of the oxidant compressor, reduce surging of theoxidant compressor, adjust a total inlet flow rate of the oxidantcompressor, or adjust an efficiency of the oxidant compressor, or anycombination thereof, using the inlet oxidant heating system.

Embodiment 34

The method or system defined in any preceding embodiment, wherein theinstructions are configured to monitor or control operations to conveythe at least one of the first portion of the combustion products, or thesecond portion of the exhaust flow, or any combination thereof, to theinlet of the oxidant compressor using an inlet oxidant heating conduit.

Embodiment 35

The method or system defined in any preceding embodiment, wherein theinstructions are configured to monitor or control operations to:increase a pressure of the exhaust flow from the turbine using anexhaust gas blower; cool the exhaust flow from the exhaust gas blowerusing an exhaust gas cooler; and route the second portion of the exhaustflow from the exhaust gas blower to the inlet of the oxidant compressorusing the inlet oxidant heating conduit.

Embodiment 36

The method or system defined in any preceding embodiment, wherein theinstructions are configured to monitor or control operations to routethe second portion of the exhaust flow from a heat recovery steamgenerator (HRSG) to the inlet of the oxidant compressor using the inletoxidant heating conduit.

Embodiment 37

The method or system defined in any preceding embodiment, wherein theinstructions are configured to monitor or control operations to route athird portion of the oxidant flow from an intercooler to the inlet ofthe oxidant compressor using the inlet oxidant heating conduit, whereinthe intercooler is configured to cool the oxidant flow from the oxidantcompressor.

Embodiment 38

The method or system defined in any preceding embodiment, wherein theinstructions are configured to monitor or control operations to route afourth portion of the oxidant flow from a booster oxidant compressor tothe inlet of the oxidant compressor using the inlet oxidant heatingconduit, wherein the booster oxidant compressor is configured tocompress the oxidant flow from the oxidant compressor.

Embodiment 39

The method or system defined in any preceding embodiment, wherein theinstructions are configured to monitor or control operations to route atleast one of the first portion of the combustion products, or the secondportion of the exhaust flow, or any combination thereof, from at leastone of a compressor inlet of the exhaust gas compressor, a compressoroutlet of the exhaust gas compressor, a compressor stage of the exhaustgas compressor, the turbine combustor, a turbine inlet of the turbine, aturbine stage of the turbine, a turbine outlet of the turbine, anexhaust gas processing system, a second gas turbine engine, or acombustion system, or any combination thereof, using the inlet oxidantheating conduit.

Embodiment 40

The method or system defined in any preceding embodiment, wherein theinstructions are configured to monitor or control operations to: routean inlet oxidant flow to the inlet of the oxidant compressor using anoxidant inlet conduit; and route the at least one of the first portionof the combustion products, or the second portion of the exhaust flow,or any combination thereof, from the inlet oxidant heating conduit tothe oxidant inlet conduit.

Embodiment 41

The method or system defined in any preceding embodiment, wherein theinstructions are configured to monitor or control operations to adjust aflow rate of the at least one of the first portion of the combustionproducts, or the second portion of the exhaust flow, or any combinationthereof, using an inlet oxidant heating control valve.

Embodiment 42

The method or system defined in any preceding embodiment, wherein theinstructions are configured to monitor or control operations to providea signal indicative of at least one of an inlet temperature of oxidantcompressor, a differential pressure of the oxidant compressor, a totalinlet flow rate of the oxidant compressor, or an efficiency of theoxidant compressor, or any combination thereof, from a sensor to acontrol system.

Embodiment 43

The method or system defined in any preceding embodiment, wherein theinstructions are configured to monitor or control operations to adjustthe inlet oxidant heating control valve in response to the signal fromthe sensor using the control system.

Embodiment 44

The method or system defined in any preceding embodiment, wherein theinstructions are configured to monitor or control operations to adjust aflow rate of at least one of the first portion of the combustionproducts, or the second portion of the exhaust flow, or any combinationthereof, using the inlet oxidant heating system to maintain an angle ofan inlet guide vane within a range, wherein the inlet guide vane iscoupled to an inlet of the oxidant compressor and is configured toadjust a total inlet flow rate of the oxidant compressor.

This written description uses examples to disclose the invention,including the best mode, and also to enable any person skilled in theart to practice the invention, including making and using any devices orsystems and performing any incorporated methods. The patentable scope ofthe invention is defined by the claims, and may include other examplesthat occur to those skilled in the art. Such other examples are intendedto be within the scope of the claims if they have structural elementsthat do not differ from the literal language of the claims, or if theyinclude equivalent structural elements with insubstantial differencesfrom the literal language of the claims.

The invention claimed is:
 1. A system, comprising: an oxidant compressor; and a gas turbine engine, comprising: a combustor section having a turbine combustor, wherein the turbine combustor is configured to produce combustion products; a turbine driven by the combustion products from the turbine combustor, wherein the turbine is configured to discharge an exhaust flow; an exhaust gas compressor driven by the turbine, wherein the exhaust gas compressor is configured to compress and route a first portion of the exhaust flow to the turbine combustor, and the oxidant compressor is configured to compress and route an oxidant flow to the turbine combustor; and an inlet oxidant heating system coupled to a plurality of heating gas sources, wherein the inlet oxidant heating system comprises a combustion products extraction conduit disposed between the turbine combustor and the turbine and an exhaust flow extraction conduit disposed between the turbine and the exhaust gas compressor, and wherein the inlet oxidant heating system is configured to route a first portion of the combustion products through the combustion products extraction conduit, or a second portion of the exhaust flow through the exhaust flow extraction conduit, or both, to an inlet of the oxidant compressor.
 2. The system of claim 1, wherein the inlet oxidant heating system is configured to combine an oxidant inlet flow to the oxidant compressor with the first portion of the combustion products, or the second portion of the exhaust flow, or both.
 3. The system of claim 1, wherein the inlet oxidant heating system comprises an inlet oxidant heating conduit configured to receive the first portion of the combustion products from the combustion products extraction conduit, or the second portion of the exhaust flow from the exhaust flow extraction conduit, or both, and to convey the first portion of the combustion products, the second portion of the exhaust flow, or both to the inlet of the oxidant compressor.
 4. The system of claim 3, comprising: an exhaust gas blower configured to increase a pressure of the exhaust flow from the turbine; and an exhaust gas cooler configured to cool exhaust flow from the exhaust gas blower, wherein the inlet oxidant heating conduit is coupled between the exhaust gas blower and the exhaust gas cooler.
 5. The system of claim 4, comprising a heat recovery steam generator (HRSG) disposed upstream of the exhaust gas blower, wherein the HRSG is configured to generate steam from the exhaust flow from the turbine.
 6. The system of claim 3, comprising an intercooler configured to cool the oxidant flow from the oxidant compressor, wherein the inlet oxidant heating conduit is coupled downstream of the intercooler and is configured to convey a first portion of the oxidant flow to the inlet of the oxidant compressor.
 7. The system of claim 3, comprising a booster oxidant compressor configured to compress the oxidant flow from the oxidant compressor, wherein the inlet oxidant heating conduit is coupled downstream of the booster oxidant compressor and is configured to convey a first portion of the oxidant flow to the inlet of the oxidant compressor.
 8. The system of claim 3, wherein the inlet oxidant heating conduit is coupled to at least one of a compressor inlet of the exhaust gas compressor, a compressor outlet of the exhaust gas compressor, a compressor stage of the exhaust gas compressor, the turbine combustor, a turbine inlet of the turbine, a turbine stage of the turbine, a turbine outlet of the turbine, an exhaust gas processing system, a second gas turbine engine, the combustion products extraction conduit, the exhaust gas extraction conduit, or a combustion system, or any combination thereof.
 9. The system of claim 1, comprising an exhaust gas extraction system coupled to the gas turbine engine, and a hydrocarbon production system coupled to the exhaust gas extraction system.
 10. The system of claim 1, wherein the gas turbine engine is a stoichiometric exhaust gas recirculation (SEGR) gas turbine engine.
 11. A method, comprising: driving a turbine of a gas turbine engine with combustion products from a turbine combustor; driving an exhaust gas compressor using the turbine; compressing and routing an exhaust flow from the turbine to the turbine combustor using the exhaust gas compressor; compressing and routing an oxidant flow to the turbine combustor using an oxidant compressor; and routing a first portion of the combustion products from a first conduit disposed between the turbine combustor and the turbine to a first control valve of an inlet oxidant heating system and a second portion of the exhaust flow from a second conduit disposed between the turbine and the exhaust gas compressor to a second control valve of the inlet oxidant heating system, wherein the first control valve and the second control valve are coupled to an inlet of the oxidant compressor.
 12. The method of claim 11, comprising mixing an oxidant inlet flow to the oxidant compressor with the at least one of the first portion of the combustion products from the first conduit, or the second portion of the exhaust flow from the second conduit, or any combination thereof using a mixer.
 13. The method of claim 11, comprising at least one of reducing icing of the oxidant compressor, reducing surging of the oxidant compressor, adjusting a total inlet flow rate of the oxidant compressor, or adjusting an efficiency of the oxidant compressor, or any combination thereof, using the inlet oxidant heating system.
 14. The method of claim 11, comprising conveying the at least one of the first portion of the combustion products from the first conduit, or the second portion of the exhaust flow from the second conduit, or any combination thereof, to the inlet of the oxidant compressor using an inlet oxidant heating conduit.
 15. The method of claim 14, comprising: routing an inlet oxidant flow to the inlet of the oxidant compressor using an oxidant inlet conduit; and routing the at least one of the first portion of the combustion products from the first conduit, or the second portion of the exhaust flow from the second conduit, or any combination thereof, from the inlet oxidant heating conduit to the oxidant inlet conduit.
 16. The method of claim 11, comprising adjusting a flow rate of the at least one of the first portion of the combustion products from the first conduit, or the second portion of the exhaust flow from the second conduit, or any combination thereof, using an inlet oxidant heating control valve.
 17. The method of claim 16, comprising providing a signal indicative of at least one of an inlet temperature of oxidant compressor, a differential pressure of the oxidant compressor, a total inlet flow rate of the oxidant compressor, or an efficiency of the oxidant compressor, or any combination thereof, from a sensor to a control system.
 18. The method of claim 11, comprising adjusting a flow rate of at least one of the first portion of the combustion products from the first conduit, or the second portion of the exhaust flow from the second conduit, or any combination thereof, using the inlet oxidant heating system to maintain an angle of an inlet guide vane within a range, wherein the inlet guide vane is coupled to the inlet of the oxidant compressor and is configured to adjust a total inlet flow rate of the oxidant compressor.
 19. A system, comprising: instructions disposed on a non-transitory, machine readable medium; a processor configured to execute the instructions to: drive a turbine of a gas turbine engine with combustion products from a turbine combustor; drive an exhaust gas compressor using the turbine; compress and route an exhaust flow from the turbine to the turbine combustor using the exhaust gas compressor; compress and route an oxidant flow to the turbine combustor using an oxidant compressor; and route a first portion of the combustion products from a first conduit disposed between the turbine combustor and the turbine to a first control valve of an inlet oxidant heating system and a second portion of the exhaust flow from a second conduit disposed between the turbine and the exhaust gas compressor to a second control valve of the inlet oxidant heating system, wherein the first control valve and the second control valve are coupled to an inlet of the oxidant compressor.
 20. The system of claim 19, wherein the processor is further configured to monitor or control operations to adjust a flow rate of at least one of the first portion of the combustion products from the first conduit, or the second portion of the exhaust flow from the second conduit, or any combination thereof, using the inlet oxidant heating system to maintain an angle of an inlet guide vane within a range, wherein the inlet guide vane is coupled to an inlet of the oxidant compressor and is configured to adjust a total inlet flow rate of the oxidant compressor. 